Refining assemblies and refining methods for rich natural gas

ABSTRACT

Refining assemblies and methods for refining rich natural gas containing a first methane gas and other hydrocarbons that are heavier than methane gas are disclosed. In some embodiments, the assemblies may include a methane-producing assembly configured to receive at least one liquid-containing feed stream that includes water and rich natural gas and to produce an output stream therefrom by (a) converting at least a substantial portion of the other hydrocarbons of the rich natural gas with the water to a second methane gas, a lesser portion of the water, and other gases, and (b) allowing at least a substantial portion of the first methane gas from the rich natural gas to pass through the methane-producing assembly unconverted. The assemblies may additionally include a purification assembly configured to receive the output stream and to produce a methane-rich stream therefrom having a greater methane concentration than the output stream.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part application of U.S. patentapplication Ser. No. 14/820,256, which was filed on Aug. 6, 2015 andentitled “Refining Assemblies And Refining Methods For Rich NaturalGas,” which is a continuation-in-part application of U.S. patentapplication Ser. No. 14/734,763, which was filed on Jun. 9, 2015 andentitled “Refining Assemblies And Refining Methods For Rich NaturalGas,” which claims the benefit of U.S. Provisional Patent ApplicationSer. No. 62/078,505, which was filed on Nov. 12, 2014 and entitled“Process and Method of Refining Wet Natural Gas,” and the benefit ofU.S. Provisional Patent Application Ser. No. 62/128,682, which was filedon Mar. 5, 2015 and entitled “Membrane-Assisted Process and Method ofRefining Wet Natural Gas.” The complete disclosures of the aboveapplications are hereby incorporated by reference for all purposes.

BACKGROUND OF THE DISCLOSURE

Rich natural gas is a mixture of hydrocarbon compounds that includesmethane gas and other hydrocarbon compounds (or other hydrocarbons)heavier than methane gas. Rich natural gas may include methane gas inany concentration, such as 50% or higher. The other hydrocarboncompounds may include any compounds with hydrogen atoms and two or morecarbon atoms, such as ethane, propane, butane, isobutene, pentane,propylene, and/or other hydrocarbon compounds. Rich natural gas may befound in crude oil wells, gas wells, condensate wells, and/or othersources. In crude oil wells, the rich natural gas may be dissolved inoil at the high pressures existing in a well and/or as a gas cap abovethe oil.

The rich natural gas may need to be purified to at least substantiallyremove or separate the other hydrocarbon compounds from the methane gasbefore the natural gas is used. The purified or product stream may beused in a variety of applications. One such application is forcombustion engines, such as the combustion engines used in commercialengine-driven generators (gensets). The separated other hydrocarboncompounds also may be used in a variety of applications, such as inputsfor petrochemical plants, space heating and cooking, and for blendinginto vehicle fuel.

SUMMARY OF THE DISCLOSURE

Some embodiments may provide a refining assembly for rich natural gascontaining a first methane gas and other hydrocarbons that are heavierthan methane gas. In some embodiments, the refining assembly may includea methane-producing assembly configured to receive at least oneliquid-containing feed stream that includes water and rich natural gasand to produce an output stream therefrom by (a) converting at least asubstantial portion of the other hydrocarbons of the rich natural gaswith the water to a second methane gas, a lesser portion of the water,and other gases, and (b) allowing at least a substantial portion of thefirst methane gas from the rich natural gas to pass through themethane-producing assembly unconverted. The refining assembly mayadditionally include a purification assembly configured to receive theoutput stream and to produce a methane-rich stream therefrom having agreater methane concentration than the output stream.

In some embodiments, the refining assembly may include a vaporizerconfigured to receive and vaporize at least a portion of at least oneliquid-containing feedstream that includes water and rich natural gas toform an at least substantially vaporized stream. The refining assemblymay additionally include a methane-producing reactor containing acatalyst and configured to receive the vaporized feed stream and toproduce an output stream by (a) converting at least a substantialportion of the other hydrocarbons with the water to a second methanegas, a lesser portion of the water, hydrogen gas, and carbon oxide gas,and (b) allowing at least a substantial portion of the first methane gasfrom the rich natural gas stream to pass through the methane-producingreactor unconverted. The refining assembly may further include a firstheating assembly configured to receive at least one fuel stream and atleast one air stream and produce a heated exhaust stream for heating atleast one of the vaporizer to at least a minimum vaporizationtemperature or the methane-producing reactor to at least a minimummethane-producing temperature. The refining assembly may additionallyinclude a purification assembly configured to receive the output streamand to produce a methane-rich stream therefrom having a greater methaneconcentration than the output stream.

Some embodiments may provide a method of refining rich natural gascontaining a first methane gas and other hydrocarbons that are heavierthan methane gas. In some embodiments, the method may include convertingat least a substantial portion of the other hydrocarbons of the richnatural gas with water to an output stream containing a second methanegas, a lesser portion of the water, hydrogen gas, and carbon oxide gas.Converting at least a substantial portion of the other hydrocarbons mayinclude not converting at least a substantial portion of the firstmethane gas from the rich natural gas. The method may additionallyinclude removing at least a portion of the water from the output streamto produce an at least substantially dried stream therefrom. The methodmay further include converting at least a portion of the carbon oxidegas and at least a portion of the hydrogen gas from the at leastsubstantially dried stream to methane gas to form an intermediate streamtherefrom containing a lower concentration of hydrogen gas and carbonoxide gas compared to the at least substantially dried stream. Themethod may additionally include separating, from the intermediatestream, at least a portion of the carbon oxide gas to form a byproductstream therefrom. The remaining portion of the intermediate stream mayform at least part of a methane-rich stream having a greater methaneconcentration than the intermediate stream.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view of an example of a refining assembly for richnatural gas.

FIG. 2 is a schematic view of an example of a methane-producing assemblyof the refining assembly of FIG. 1.

FIGS. 3-5 are schematic views of different configurations for themethane-producing assembly of FIG. 2.

FIG. 6 is a schematic view of an example of a purification assembly ofthe refining assembly of FIG. 1.

FIG. 7 is a schematic view of an example of a water removal assembly ofthe purification assembly of FIG. 6.

FIG. 8 is a schematic view of an example of a gas removal assembly ofthe purification assembly of FIG. 6.

FIGS. 9-10 are schematic views of different configurations for the gasremoval assembly of FIG. 8.

FIG. 11 is a schematic view of another example of a gas removal assemblyof the purification assembly of FIG. 6.

FIG. 12 is a schematic view of another example of a refining assemblyfor rich natural gas.

FIG. 13 is a schematic view of an example of a methane-producingassembly of the refining assembly of FIG. 12.

FIG. 14 is a schematic view of an example of a gas removal assembly ofthe refining assembly of FIG. 12.

FIG. 15 is a schematic view of another example of a gas removal assemblyof the refining assembly of FIG. 12.

FIG. 16 is a schematic view of a further example of a gas removalassembly of the refining assembly of FIG. 12.

FIG. 17 is a schematic view of another example of a gas removal assemblyof the refining assembly of FIG. 12.

FIG. 18 is a schematic view of a further example of a gas removalassembly of the refining assembly of FIG. 12.

FIG. 19 is a schematic view of another example of a gas removal assemblyof the refining assembly of FIG. 12.

FIG. 20 is a schematic view of a membrane contactor of the gas removalassembly of FIG. 19.

FIG. 21 is a schematic view of an example of a membrane of the membranecontactor of FIG. 20.

FIG. 22 is a schematic view of another example of a membrane of themembrane contactor of FIG. 20.

FIG. 23 is a schematic view of a further example of a gas removalassembly of the refining assembly of FIG. 12.

FIG. 24 is a schematic view of another example of a refining assemblyfor rich natural gas.

FIG. 25 is an example of a plate burner of a heating assembly for arefining assembly.

FIG. 26 is a schematic view of a further example of a refining assemblyfor rich natural gas.

FIG. 27 is an example of a method of refining rich natural gas.

DETAILED DESCRIPTION OF THE DISCLOSURE

FIG. 1 shows an example of a refining assembly 30 for rich natural gas.Unless specifically excluded refining assembly 30 may include one ormore components of other refining assemblies and/or other assembliesdescribed in this disclosure. The refining assembly may include anysuitable structure configured to receive at least one rich natural gasstream 32 and generate a product methane stream 34. For example, therefining assembly may include a feedstock delivery system 36 and a fuelprocessing system 38. The feedstock delivery system may include anysuitable structure configured to selectively deliver at least one feedstream 40 (which includes rich natural gas stream 32) to the fuelprocessing assembly.

In some embodiments, feedstock delivery system 36 may additionallyinclude any suitable structure configured to selectively deliver atleast one fuel stream 44 from a fuel source 42 (such as storagecylinder(s) or vessel(s)) to one or more burners and/or other heatingassemblies of fuel processing system 38. The feedstock delivery systemmay include any suitable delivery mechanisms, such as pumps,compressors, and/or other mechanism(s) for propelling fluid streams. Insome embodiments, feedstock delivery system 36 may be configured todeliver feed stream(s) 40 and/or fuel stream(s) 44 without requiring theuse of pumps, compressors, and/or other electrically poweredfluid-delivery mechanisms. In some embodiments, feedstock deliverysystem may include a heat exchanger and/or other heating device(s)configured to pre-heat or heat one more streams, such as feed stream(s)40, prior to fuel processing system 38.

Feed stream 40 may include a methane-production fluid stream 46 and richnatural gas stream 32. The methane-production fluid stream may includeat least one methane-production fluid, such as water from a water source41. Water source 41 may include a connection to publicly available water(e.g., tap water, running water, municipal water, etc.), a storagevessel, a surface water source (e.g., river, lake, etc.), a groundwatersource, and/or other source(s). In some embodiments, water from watersource 41 may be deionized prior to delivery as methane-production fluidstream 46. Rich natural gas stream 32 may be from a rich natural gassource 48, such as a well head, a storage vessel, and/or othersource(s). When methane-production fluid stream 46 includes liquidwater, feed stream 40 may sometimes be referred to as a“liquid-containing feedstream.” The ratio of water to rich natural gasdelivered by the feedstock delivery system to the fuel processing systemmay vary according to one or more factors, such as the amount of carbonin the rich natural gas, user preferences, design of the fuel processingsystem, mechanism(s) used by the fuel processing system to generate theproduct methane stream, etc. For example, the molar ratio of water tocarbon atoms or steam-to-carbon ratio may be 1:1 to 4:1, preferably1.5:1 to 3:1, and particularly preferred 1.8:1 to 2.5:1. In someembodiments, the feedstock delivery system may control the flow ofmethane-production fluid stream 46 and/or rich natural gas stream 32 toprovide one or more of the above molar ratios to the fuel processingsystem.

In some embodiments, rich natural gas stream 32 may be treated in adesulfurization assembly 50 to produce a desulfurized rich natural gasstream 52, such as prior to delivery to fuel processing system 38Desulfurization assembly 50 may include any suitable structureconfigured to use any suitable mechanism(s) to at least substantiallyremove sulfur compounds (e.g., organosulfur compounds, hydrogensulfides, carbonyl sulfides, and/or other sulfur-containing compounds)from the rich natural gas. For example, desulfurization assembly 50 mayinclude a tower containing an amine solution (e.g., monoethanolamine anddiethanolamine) that is configured to absorb sulfur compounds.

Although feedstock delivery system 36 is shown to be configured todeliver a single feed stream 40, the feedstock delivery system may beconfigured to deliver two or more feed streams 40. Those streams maycontain the different compositions, at least one common component, nocommon components, or the same compositions. For example, feedstockdelivery system may be configured to deliver methane-production fluidstream 46 and rich natural gas stream 32 separately into the fuelprocessing system. Additionally, although feedstock delivery system 36may, in some embodiments, be configured to deliver a single fuel stream44, the feedstock delivery system may be configured to deliver two ormore fuel streams.

The fuel streams may have different compositions, at least one commoncomponent, no common components, or the same compositions. Moreover, therich natural gas, methane-production fluid, and fuel streams may bedischarged from the feedstock delivery system in different phases. Forexample, one or more of the streams may be liquid stream(s) (such as thewater and/or fuel streams) while the one or more of the other streamsmay be gas streams (such as the rich natural gas stream(s)).Furthermore, although refining assembly 30 is shown to include a singlefeedstock delivery system 36, the refining assembly may include two ormore feedstock delivery systems 36.

In some embodiments, feedstock delivery system 36 may include anysuitable structure configured to selectively deliver at least one richnatural gas slip stream 53 from rich natural gas source 48 (ordesulfurization assembly 50) to combine or blend with methane-richstream 64 to produce product methane stream 34 therefrom. The feedstockdelivery system may include any suitable delivery mechanisms, such aspumps, compressors, and/or other mechanism(s) for propelling fluidstreams. In some embodiments, feedstock delivery system 36 may beconfigured to deliver slip stream(s) 53 without requiring the use ofpumps, compressors, and/or other electrically powered fluid-deliverymechanisms. In some embodiments, feedstock delivery system may include aheat exchanger and/or other heating device(s) configured to pre-heat orheat slip stream 53 prior to combining or blending with methane-richstream 64. The feedstock delivery system may be configured to deliverany suitable amount to the methane-rich stream. For example, the richnatural gas slip stream may be about 5% to about 30% of the productmethane stream. Although feedstock delivery system 36 is shown tocombine or blend rich natural gas slip stream(s) 53 with methane-richstream 64, the feedstock delivery system may alternatively, oradditionally, combine or blend rich natural gas slip stream(s) 53 withone or more other streams, such as output stream 56.

Additionally, feedstock delivery system 36 may include any suitablecontrol and/or regulating mechanisms, such as control valves and/orother mechanism(s) for controlling and/or regulating one or morecharacteristics and/or properties of one or more fluid streams. Thecontrol and/or regulating mechanisms may control and/or regulate one ormore characteristics and/or properties of the fluid stream(s) based onone or more characteristics and/or properties of one or more other fluidstreams. The one or more characteristics and/or properties may bepredetermined prior to operation of refining assembly 30 and/or may bedetermined and/or measured during operation of the refining assembly,such as via one or more sensors. Examples of characteristics and/orproperties include mass, volume, flow, temperature, electrical current,pressure, refractive index, thermal conductivity, density, viscosity,optical absorbance, electrical conductivity, heating value, methanenumber, mass flow rate, and concentration of one or more fluid streamcomponents, such as hydrogen, carbon oxide(s), methane, etc.

As used herein, “carbon oxide” refers to carbon dioxide and/or carbonmonoxide. “Methane number,” as used herein, refers to the tendency of aparticular stream, such a product methane stream 34, to “knock” orundergo premature ignition in an internal combustion engine. Methanenumber of some individual component gases are:

Methane=100

Ethane=44

Propane=32

Butane (commercial)=15

n-Butane=10

Hydrogen=0

Methane number is further discussed in the Gas Engines Application andInstallation Guide (October 1997) by Caterpillar, the completedisclosure of which is hereby incorporated by reference for allpurposes.

In some embodiments, feedstock delivery system 36 may adjust one or morecharacteristics of rich natural gas slip stream 53 based on one or morecharacteristics of other streams, such as output stream 56, methane-richstream 64, and/or product methane stream 34. Feedstock delivery system36 may adjust the characteristic(s) of rich natural gas slip stream 53such that the characteristic(s) of one or more other streams are aboveminimum(s), below maximum(s), or within predetermined range(s). Forexample, the feedstock delivery system may adjust flowrate of the richnatural gas slip stream based on one or more characteristics of productmethane stream 34, such as methane content, carbon dioxide content,heating value, methane number, etc. In some embodiments, feedstockdelivery system 36 may be configured to adjust flowrate of rich naturalgas slip stream 53 to methane-rich stream 64 based, at least in part, onat least one measured characteristic of the product methane stream suchthat the product methane stream has at least one of a minimum heatingvalue or a minimum methane number.

In some embodiments, the desired heating value may be between about 800and about 1200 Btu/cubic foot (e.g., minimum heating value of about 800)and the desired methane number may be above about 70 for product methanestream 34. For example, when methane-rich stream 64 includes about 75%methane, about 15% carbon dioxide, and about 10% water vapor, one ormore sensors may determine that the methane number may be about 100 toabout 110 and the heating value may be about 680 Btu/cubic foot. In theabove example, methane number may be above the minimum methane numberbut the heating value may be below the minimum heating value. Feedstockdelivery system 36 may adjust the rich natural gas slip stream 53 toraise the heating value of the product methane stream to be above about800 Btu/cubic foot.

Fuel processing system 38 may include any suitable structure configuredto process feed stream(s) 40, such as to increase concentration ofmethane gas and/or reduce concentration of other components in the richnatural gas stream. For example, fuel processing system 38 may include amethane-producing assembly 54 configured to produce an output stream 56containing methane gas via any suitable methane-producing mechanism(s).The output stream may include methane gas as at least a majoritycomponent and may include additional gaseous component(s). Output stream56 may therefore be referred to as a “mixed gas stream” that containsmethane gas as its majority component but which includes water and othergases.

Methane-producing assembly 54 may include any suitablecatalyst-containing bed or region. When the methane-producing mechanismis heavy hydrocarbon reforming, the methane-producing assembly mayinclude a suitable heavy hydrocarbon reforming catalyst 58 to facilitateproduction of output stream(s) 56 from feed stream(s) 40. In such anembodiment, methane-producing assembly 54 may convert at least asubstantial portion of other hydrocarbons that are heavier than methanegas with water to methane gas, a lesser portion of the water, and othergases. In some embodiments, the conversion of the other hydrocarbonsthat are heavier than methane gas may be adjusted based on one or morecharacteristics and/or properties of the methane-rich stream and/orproduct methane stream, such as heating value and/or methane number. Forexample, the conversion may be adjusted to allow at least a portion ofthe other hydrocarbons that are heavier than methane gas to passunconverted through the methane-producing assembly to raise the methanenumber of the product methane stream.

Additionally, methane-producing assembly 54 may allow at least asubstantial portion of methane gas from rich natural gas stream(s) 32 topass through the methane-producing assembly unchanged, unreacted, and/orunconverted. In other words, methane gas in output stream 56 may include(1) methane gas in the rich natural gas stream(s) prior tomethane-producing assembly 54 and fuel processing system 38, and (2)methane gas that was produced in methane-producing assembly 54 from theconversion of other hydrocarbons in the rich natural gas stream(s) withwater. When heavy hydrocarbon reforming is the methane-producingmechanism in methane-producing assembly 54, methane-producing assembly54 may sometimes be referred to as a “heavy hydrocarbon reformer,” andoutput stream 56 may sometimes be referred to as a “reformate stream.”The other gases that may be present in the reformate stream may includecarbon oxide gas and/or hydrogen gas.

In some embodiments, fuel processing system 38 may include apurification (or separation) assembly 62, which may include any suitablestructure configured to produce at least one methane-rich stream 64 fromoutput (or mixed gas) stream 56. Methane-rich stream 64 may include agreater methane concentration than output stream 56 and/or a reducedconcentration of water and one or more other gases (or impurities) thatwere present in that output stream. Product methane stream 34 includesat least a portion of methane-rich stream 64. Thus, product methanestream 34 and methane-rich stream 64 may be the same stream and have thesame composition and flow rates. Alternatively, some of the purifiedmethane gas in methane-rich stream 64 may be stored for later use, suchas in a suitable methane storage assembly and/or consumed by the fuelprocessing system. Purification assembly 62 also may be referred to as a“methane purification device” or a “methane processing assembly.”

In some embodiments, purification assembly 62 may produce one or morestreams 66 other than methane-rich stream 64. For example, purificationassembly 62 may produce at least one reclaimed water stream 68, whichmay be at least substantially liquid water. The reclaimed water streammay be discharged to drain, stored for later use, deionized, sent tofeedstock delivery system 36 (such as to supplement water source 41),and/or otherwise utilized, stored, and/or disposed. Additionally,purification assembly 62 may produce the reclaimed water stream as acontinuous stream responsive to the delivery of output stream 56, or mayproduce that stream intermittently, such as in a batch process or whenthe water portion of the output stream is retained at least temporarilyin the purification assembly.

Additionally, purification assembly 62 may produce at least onebyproduct stream 70, which may contain no methane gas or some methanegas. The byproduct stream may be exhausted, sent to a burner assemblyand/or other combustion source, sent to feedstock delivery system 36(such as to supplement fuel source 42), stored for later use, and/orotherwise utilized, stored, and/or disposed. Additionally, purificationassembly 62 may produce the byproduct stream as a continuous streamresponsive to the delivery of output stream 56, or may produce thatstream intermittently, such as in a batch process or when the byproductportion of the output stream is retained at least temporarily in thepurification region.

Fuel processing system 38 may include one or more purificationassemblies 62 configured to produce one or more reclaimed water streamsand/or one or more byproduct streams. The byproduct streams 70 maycontain sufficient amounts of methane gas and/or otherflammable/combustible gases to be suitable for use as a fuel stream,such as for one or more heating assemblies of the fuel processingsystem. In some embodiments, the byproduct stream may have sufficientfuel value or methane content to enable one or more heating assembliesto maintain the methane-producing assembly at a desired operatingtemperature or within a selected range of temperatures, and/or tomaintain one or more assemblies in purification assemblies 62 at apredetermined operating temperature or within a predetermined range oftemperatures.

Purification assembly 62 may include any suitable structure configuredto enrich (and/or increase) the concentration of at least one componentof output stream 56. In most applications, methane-rich stream 64 willhave a greater methane concentration than output stream (or mixed gasstream) 56. The methane-rich stream may alternatively, or additionally,have a reduced concentration of one or more non-methane components thatwere present in output stream 56 with the methane concentration of themethane-rich stream being more, the same, or less than the outputstream.

Examples of suitable devices for purification assembly 62 include gasdryers 72 and/or water knockout devices 74, which may additionallyproduce reclaimed water stream(s) 68. Other examples of suitable devicesfor purification assembly include one or more synthetic natural gas(SNG) reactors 76, scrubbers 78, carbon oxide-selective membranes 80,and/or membrane contactors 82, which may additionally produce byproductstream(s) 70. Purification assembly 62 may include more than one type ofpurification device and the devices may have the same or differentstructures and/or operate by the same or different mechanism(s). Forexample, purification assembly 62 may include multiple gas dryers 72and/or water knockout devices 74. In some examples, a water knockoutdevice 74 and/or a gas dryer 72 may be upstream one or more of the otherdevices in purification assembly 62. For example, purification assembly62 may include a water knockout device 74 and/or a gas dryer 72 upstreameach SNG reactor 76, scrubber 78, carbon oxide-selective membrane 80,and/or membrane contactor 82

Gas dryers 72 may include devices that are capable of selectivelyremoving water vapor from a gas stream. Examples of gas dryers 72include water-selective membranes, desiccant beds, refrigeration dryers,and/or other devices for removing water vapor from gases. An example ofa suitable refrigeration dryer is the Drypoint® RA series sold by Bekoor the SPL series sold by Parker. Water knockout devices 74 may includedevices that separate out liquid water (e.g., entrained liquid water),such as coalescing filters. SNG reactors 76 may convert carbon oxide gas(such as carbon dioxide gas and/or carbon monoxide gas) and hydrogen gasto produce methane gas and water. In some embodiments, SNG reactors 76may cause hydrogen to react primarily with carbon dioxide gas, andsecondarily with carbon monoxide gas.

Scrubbers 78 may receive at least one absorbent that is adapted toabsorb carbon oxide gas and/or hydrogen gas. The scrubbers may includean absorber (or absorber portion) configured to direct the flow of thegas stream with carbon oxide and/or hydrogen gas through the at leastone absorbent that is adapted to absorb the carbon oxide gas and/orhydrogen gas from that gas stream. The absorbent may be a liquid and/orsolid. In some embodiments, scrubbers 78 may include a stripper (orstripper portion) downstream from the absorber portion. The stripper maybe configured to strip and/or remove at least a substantial portion ofthe carbon oxide gas and/or hydrogen gas from the absorbent.

Carbon oxide-selective membranes 80 may be permeable to carbon oxide gasand/or hydrogen gas, but are at least substantially (if not completely)impermeable to methane in output stream 56. Membranes 80 may be formedof any carbon oxide-permeable and/or hydrogen-permeable materialsuitable for use in the operating environment and parameters in whichpurification assembly 62 is operated. Examples of suitable materials formembranes 80 include cellulose acetate, polyimide, polysulfone, andpoly(amidoamine) doped poly(ethylene glycol).

Membrane contactors 82 may include devices that include carbonoxide-selective membranes to separate carbon oxide gas and/or hydrogengas, and a liquid absorbent adapted to absorb carbon oxide gas and/orhydrogen gas. For example, a permeate side of the carbon oxide-selectivemembranes may receive liquid absorbent. Carbon oxide gas and/or hydrogengas may pass from a feed side to the permeate side, and then may beabsorbed by the liquid absorbent. The membranes may provide a stableinterface to allow gas-liquid contacting over a large total surface areawithout foaming, large gas contacting columns, etc.

Methane-producing assembly 54 and/or purification assembly 62 may eachbe contained within an assembly housing or assembly shell 84. In someembodiments, purification assembly 62 may include separate assemblyhousings or assembly shells 84 for each component or set of components.For example, when purification assembly 62 includes one or more SNGreactors 76, those reactors may be contained within an assembly housingor an assembly shell 84 separate from other components or assemblies ofpurification assembly 62. Those other components also may be containedin separate assembly housings or assembly shells 84. Assembly shell 84may include insulating material 86, such as a solid insulating material,blanket insulating material, and/or an air-filled cavity. The insulatingmaterial may be internal the shell, external the shell, or both. Whenthe insulating material is external a shell, fuel processing system 38may further include an outer cover or jacket 88 external the insulation,as schematically illustrated in FIG. 1.

Fuel processing system 38 may additionally include a frame 90 thatsupports methane-producing assembly 54 and/or purification assembly 62.In some embodiments, the methane-producing assembly and/or thepurification assembly may additionally be contained within a systemhousing or system shell 92. Frame 90 and/or system shell 92 may enablecomponents of fuel processing system to be moved as a unit. The shellalso may protect components of the fuel processing system from damage byproviding a protective enclosure. In some embodiments, system shell 92may include insulating material and/or an outer cover or jacket. Thefuel processing system may include a different system frame and/orsystem shell that includes additional components of the refiningassembly, such as feedstock delivery system 36 and/or other components.

One or more components of fuel processing system 38 may either extendbeyond the frame and/or system shell or be located external the frameand/or system shell. For example, one or more components and/orassemblies of purification assembly 62 may be located external the frameand/or system shell, such as being spaced-away from the shell but influid communication by suitable fluid-transfer conduits. As anotherexample, a portion of methane-producing assembly 54 may extend beyondthe shell, such as indicated schematically with a dashed linerepresenting an alternative shell configuration in FIG. 1.

An example of a methane-producing assembly 54 is shown in FIG. 2, whichis generally indicated at 94. Unless specifically excluded,methane-producing assembly 94 may include one or more components ofother methane-producing assemblies and/or other assemblies described inthis disclosure. Methane-producing assembly 94 may include at least onevaporizing region or vaporizer 96, at least one methane-producing regionor reactor 98, and at least one heating assembly 100.

Vaporizer 96 may include any suitable structure configured to receiveand vaporize at least a portion of a liquid-containing feedstream, suchas feed stream(s) 40 that include water and rich natural gas, into oneor more vapor feed streams 104 (such as one or more at leastsubstantially vaporized streams). Feed stream(s) 40 may have a pressureof <500 psig, and preferably between 20 psig and 100 psig or between 40psig and 200 psig. In vaporizer 96, at least a substantial portion ofliquid water in feed stream(s) 40 may be vaporized into water vapor,which may mix with the rich natural gas in the feed stream(s). Thevaporized feed streams may, in some embodiments, include liquid(s). Anexample of a suitable vaporizer is a coiled tube vaporizer, such as acoiled stainless steel tube.

Since the purpose of vaporizer 96 is to generate hot steam (water vapor)to chemically react with at least a substantial portion of hydrocarboncompounds heavier than methane gas in the vapor feed stream 40 (seebelow), it is within the scope of the present disclosure that a portionor all of the steam may be produced by one or more structures and/orsystems separate from methane-producing assembly 94. For example, steammay be generated in an external boiler, or via external heat exchangers,and then supplied to methane-producing reactor 94. In this case,vaporizer 96 may be reduced in size (capacity to vaporize a stream ofwater) or even completely eliminated.

Methane-producing reactor 98 may include any suitable structureconfigured to receive one or more feed streams, such as vapor feedstreams 104 from vaporizer 96, to produce one or more output streams 56containing methane as a majority component, water, and other gases. Themethane-producing reactor may produce the output stream via any suitablemechanism(s). For example, methane-producing reactor 98 may generateoutput stream 56 via a heavy hydrocarbon reforming (HHR) reaction. Whenmethane-producing reactor 98 generates output stream 56 via a HHRreaction, that reactor may sometimes be referred to as a “heavyhydrocarbon reforming reactor” or a “HHR reactor.”

Methane-producing reactor 98 may have any suitable design, such as atubular or cylindrical design. Additionally, methane-producing reactor98 may include any suitable catalyst-containing bed or region toaccelerate chemical reaction or conversion rates. When themethane-producing mechanism is HHR, the methane-producing reactor mayinclude a suitable HHR catalyst 108 to facilitate production of outputstream(s) 56 from vapor feed stream(s) 104. Examples of suitable HHRcatalysts include nickel-based catalysts (such as Reformax® 100-RS andHyProGen® R-70, both sold by Clariant®, Louisville, Ky.; and MC-750Rsold by Unicat, Houston, Tex.) and ruthenium-based catalysts (such asM-10 sold by Clariant®, Louisville, Ky.).

Methane-producing reactor 98 may be configured to convert at least asubstantial portion of hydrocarbon compounds heavier than methane gas inthe vapor feed stream with the water in that stream to methane gas, alesser portion of the water, and other gases. Additionally,methane-producing reactor 98 may be configured to allow at least asubstantial portion of the methane gas in vapor feed stream 104 to passthrough the methane-producing reactor unconverted, unchanged, and/orunreacted. As an example, methane-producing reactor 98 may be configuredto convert propane in the vapor feed stream with the water in thatstream to methane gas, carbon oxides, hydrogen, and water as shown inthe approximate chemical reaction below.C₃H₈+6H₂O→2.1CH₄+0.7CO₂+0.2CO+1.4H₂+4.4H₂OThe above equation is only an example and does not represent all theconversions and/or reactions that may occur in the methane-producingreactor, such as when vapor feed stream 104 includes hydrocarboncompounds heavier than methane gas other than propane.

Methane-producing assembly 94 also may include a temperature modulatingassembly in the form of heating assembly 100. The heating assembly maybe configured to produce at least one heated exhaust stream (orcombustion stream) 110 from at least one heating fuel stream 112,typically as combusted in the presence of air. Heated exhaust stream 110is schematically illustrated in FIG. 2 as heating vaporizer 96 andmethane-producing reactor 98. Heating assembly 100 may include anysuitable structure configured to generate the heated exhaust stream(s),such as a burner or combustion catalyst in which a fuel is combustedwith air to produce the heated exhaust stream. The heating assembly mayinclude an ignitor or ignition source 114 that is configured to initiatethe combustion of fuel. Examples of suitable ignition sources includeone or more spark plugs, glow plugs, combustion catalyst, pilot lights,piezoelectric ignitors, spark igniters, hot surface igniters, etc.

Heating assembly 100 may achieve and/or maintain in vaporizer 96 and/ormethane-producing reactor 98 any suitable temperatures. For example,heating assembly 100 may heat vaporizer 96 to at least a minimumvaporization temperature, and/or may heat methane-producing reactor 98to at least a minimum methane-producing temperature. HHR reactors mayoperate at temperatures in the range of 200° C. to 600° C., preferably250° C. to 500° C., and more preferably 390° C. to 470° C. The abovetemperature ranges are much lower than the temperature ranges for steamreforming methane, which typically is about 800° C. to 900° C.

In some embodiments, heating assembly 100 may be configured to adjusttemperature of the heated exhaust stream(s) based, at least in part, onone or more measured characteristics of one or more other streams of therefining assembly. For example, one or more sensors (not shown) maydetermine or measure heating value and/or methane number of the productmethane stream and the heating assembly may adjust temperature of theheated exhaust stream(s) based, at least in part, on those measurements.If the measured heating value of the product methane stream is lowerthan a minimum heating value, the heating assembly may be configured tolower the temperature of one or more heated exhaust streams (such as theheated exhaust stream(s) that heat the methane-producing reactor) toallow more other hydrocarbons that are heavier than methane gas to passthrough the methane-producing reactor unconverted. For example, themethane-producing reactor may be operated at temperatures in the rangeof 350° C. to 400° C., or 300° C. to 430° C.

In some embodiments, heating assembly 100 may include a burner assembly116 and may be referred to as a combustion-based, or combustion-driven,heating assembly. In a combustion-based heating assembly, heatingassembly 100 may be configured to receive at least one fuel stream 112and to combust the fuel stream in the presence of air to provide a hotcombustion stream 110 that may be used to heat the vaporizer and/ormethane-producing reactor. Air may be delivered to the heating assemblyvia a variety of mechanisms. For example, an air stream 118 may bedelivered to the heating assembly as a separate stream, as shown in FIG.2. Alternatively, or additionally, air stream 118 may be delivered tothe heating assembly with at least one of the fuel streams 112 forheating assembly 100 and/or drawn from the environment within which theheating assembly is utilized.

Fuel stream 112 may include any combustible liquid(s) and/or gas(es)that are suitable for being consumed by heating assembly 100 to providethe desired heat output. In some embodiments, one or more fuel stream(s)112 may be delivered to the heating assembly via feedstock deliverysystem 36. Some fuel streams may be gases when delivered and combustedby heating assembly 100, while others may be delivered to the heatingassembly as a liquid stream. Examples of suitable heating fuels for fuelstreams 112 include carbon-containing feedstocks, such as methanol,methane, ethane, ethanol, ethylene, propane, propylene, butane, etc.Additional examples include low molecular weight condensable fuels, suchas liquefied petroleum gas, ammonia, lightweight amines, dimethyl ether,and low molecular weight hydrocarbons. Yet other examples includehydrogen gas and/or carbon oxide gas. For example, one or more byproductstreams 120 from other components and/or assemblies of the fuelprocessing system may be used as a suitable heating fuel for fuelstream(s) 112.

Combustion stream 110 may additionally, or alternatively, be used toheat other portions of the fuel processing system and/or other systemswith which the heating assembly is used. After combustion stream 110heats vaporizer 96, methane-producing reactor 98, and/or othercomponents and assemblies, the stream may exit as combustion exhauststream(s) 122.

Additionally, other configuration and types of heating assemblies 100may be used. For example, heating assembly 100 may be an electricallypowered heating assembly that is configured to heat vaporizer 96 and/ormethane-producing reactor 98 by generating heat using at least oneheating element (such as a resistive heating element), waste heatstream(s), solar heating, etc. In those embodiments, heating assembly100 may not receive and combust a combustible fuel stream to heatvaporizer to a suitable vaporization temperature and/or heatmethane-producing reactor to a suitable methane-producing temperature.Examples of heating assemblies are disclosed in U.S. Pat. No. 7,632,322,the complete disclosure of which is hereby incorporated by reference forall purposes.

The heating assembly also may be configured to heat other componentsand/or assemblies, such as a feedstock delivery system, the feedstocksupply streams, purification assemblies, or any suitable combination ofthose systems, streams, and regions. The heating assembly mayadditionally be configured to heat other components of the refiningassembly. For example, the heated exhaust stream may be configured toheat a pressure vessel and/or other canister containing the heating fueland/or the hydrogen-production fluid that forms at least portions offeed stream(s) 40 and fuel stream(s) 112.

Heating assembly 100 may be housed in an assembly shell or housing 124with the vaporizer and/or methane-producing reactor. The heatingassembly may be separately positioned relative to the vaporizer and/ormethane-producing reactor but in thermal and/or fluid communication withthose components to provide the desired heating. Heating assembly 100may be located partially or completely within the common shell, and/orat least a portion (or all) of the heating assembly may be locatedexternal that shell. When the heating assembly is located external theshell, the hot combustion gases from burner assembly 116 may bedelivered via suitable heat transfer conduits to one or more componentswithin the shell.

Although methane-producing assembly 94 is shown to include a singlevaporizer 96, a single methane-producing reactor 98, and a singleheating assembly 100, the methane-producing assembly may include two ormore vaporizers 96, two or more methane-producing reactors 98, and/ortwo or more heating assemblies 100, as shown in dashed lines in FIG. 2.

Vaporizer 96, methane-producing reactor 98, and heating assembly 100 maybe arranged in any suitable configuration. Examples of suitableconfigurations are shown in FIGS. 3-5. In FIG. 3, vaporizer 96 isdisposed between methane-producing reactor 98 and heating assembly 100.In FIG. 4, vaporizer 96 and methane-producing reactor 98 areside-by-side with heating assembly 100 below the vaporizer andmethane-producing reactor. In FIG. 5, vaporizer 96 and methane-producingreactor 98 are side-by-side with heating assembly 100 spaced from andadjacent to vaporizer 96.

An example of a purification assembly 62 is shown in FIG. 6, which isgenerally indicated at 126. Unless specifically excluded, purificationassembly 126 may include one or more components of other purificationassemblies described in this disclosure. Purification assembly 126 mayinclude at least one water removal assembly 128 and at least one gasremoval assembly 130.

Water removal assembly 128 may include any suitable structure configuredto remove water from output stream 56 of methane-producing assembly 54(or an intermediate stream 132) to produce an at least substantiallydried stream 134 (such as an at least substantially dried outputstream). The water removed by the water removal assembly may be in theform of water vapor and/or liquid water. Water removal assembly 128 mayproduce one or more reclaimed water streams 135 from the water removedfrom output stream 56 and/or intermediate stream 132. The reclaimedwater may be pumped or otherwise transported to a feedstock deliverysystem for use in the methane-producing assembly and/or may be stored,sent to drain, or otherwise disposed.

Gas removal assembly 130 may include any suitable structure configuredto remove one or more other gases (such as gases other than methane gas)from at least substantially dried stream 134 to form methane-rich stream64. For example, gas removal assembly 130 may be configured to removecarbon oxide gas and/or hydrogen gas from at least substantially driedstream 134. When purification assembly 126 includes two or more gasremoval assemblies 130, one or more upstream gas removal assemblies mayremove one or more other gases from at least substantially dried stream134 to form one or more intermediate streams 138. Gas removalassembly(ies) 130 may produce one or more byproduct streams 140 from theremoved gases, such as carbon oxide gas and hydrogen gas. The byproductstreams may be pumped or otherwise transported to feedstock deliverysystem 36 and/or one or more heating assemblies to burn as fuel, and/ormay be stored, discharged, or otherwise disposed.

In some embodiments, gas removal assembly 130 may include a carbonoxide-selective membrane assembly having one or more carbonoxide-selective membranes 141. The carbon oxide-selective membranes mayinclude any suitable structure configured to remove carbon oxide gasand/or hydrogen gas from at least substantially dried stream(s) 134and/or intermediate stream(s) 138. Carbon oxide-selective membranes 141may have a relatively high permeability to carbon oxide gas and/orhydrogen gas over methane gas such that dried output stream 134 and/orintermediate stream 138, when passed through one or more of the carbonoxide-selective membranes, would be preferentially depleted of at leasta portion of carbon oxide gas and/or hydrogen gas. The carbon oxide gasand/or hydrogen gas may form byproduct stream(s) 140. Examples ofsuitable carbon oxide-selective membranes include cellulose acetate(from UOP), polyimide and polysulfone (from Air Products and MembraneTechnology and Research, Inc.), and poly(amidoamine) doped poly(ethyleneglycol) (from Kyushu University, Japan).

When gas removal assembly 130 includes one or more carbonoxide-selective membranes 141, at least substantially dried stream 134and/or intermediate stream 138 may be at a pressure greater than 40psig, and preferably greater than 80 psig. Gas removal assembly 130 mayinclude one or more pumps or compressors to provide streams 134 and/or138 at the pressures described above to the carbon oxide-selectivemembranes. Methane-rich stream(s) 64 and/or intermediate stream(s) 138exiting the carbon oxide-selective membranes may contain less than 5% ofcarbon dioxide, and preferably less than 3% of carbon dioxide.

Purification assembly 126 may include any suitable number of waterremoval assemblies 128 and/or any suitable number of gas removalassemblies 130, as shown in the dashed boxes in FIG. 6. When thepurification assembly includes two or more water removal assemblies 128,those assemblies may be the same or different from each other.Additionally, when the purification assembly includes two or more gasremoval assemblies 130, those assemblies may be the same or differentfrom each other. For example, one or more gas assemblies 130 may beconfigured to remove one or more other gases via a first mechanism,while one or more other gas assemblies 130 may be configured to removeone or more other gases via a second mechanism that is different fromthe first mechanism.

Moreover, when there are two or more gas assemblies, those assembliesmay remove different types of other gases and/or remove those gases indifferent proportions. Furthermore, the water removal assemblies and gasassemblies may be in any suitable sequence or order. In someembodiments, purification assembly 126 may include a water removalassembly 128 upstream of one or more gas removal assemblies 130. Forexample, purification assembly 126 may include a water removal assembly,a first gas removal assembly, and a second gas removal assembly. In someembodiments, purification assembly 126 may include a water removalassembly 128 upstream each gas removal assembly 130. For example,purification assembly 126 may include a first water removal assembly, afirst gas removal assembly, a second water removal assembly, and asecond gas removal assembly.

An example of a water removal assembly 128 is shown in FIG. 7, which isgenerally indicated at 142. Unless specifically excluded, water removalassembly 142 may include one or more components of other water removalassemblies and/or other assemblies described in this disclosure. Waterremoval assembly 142 may include at least one gas dryer 144, which mayinclude any suitable structure configured to remove at least asubstantial portion of water vapor from one or more streams 146, such asan output stream from a methane-producing assembly or an intermediatestream from an upstream gas removal assembly, to form an at leastsubstantially dried stream 148. For example, gas dryer 144 may includeone or more water-selective membranes, dessicant beds, refrigerantdryers, and/or other devices. Gas dryer 144 is preferred to include oneor more refrigerant dryers, such as the Drypoint® RA series sold by Bekoand SPL series sold by Parker.

In some embodiments, water removal assembly 142 may include at least onewater knockout device 150 configured to remove at least a substantialportion of liquid water from stream 146. For example, when entrainedliquid water is present in output stream(s) 146 in addition to watervapor, the water removal assembly may include one or more water knockoutdevices 150. Water removal assembly 142 may produce one or morereclaimed water streams 135 from the water vapor and/or liquid waterremoved from stream(s) 146. The reclaimed water streams may bedischarged, pumped or otherwise transported to a feedstock deliverysystem, and/or stored, sent to drain, or otherwise disposed.

An example of a gas removal assembly 130 is shown in FIG. 8, which isgenerally indicated at 154. Unless specifically excluded, gas removalassembly 154 may include one or more components of other gas removalassemblies described in this disclosure. Gas removal assembly 154 mayinclude at least one gas removal region or reactor 156 and at least oneheating assembly 158.

Gas removal reactor 156 may include any suitable structure configured toreceive one or more feed streams, such as an at least substantiallydried stream 160 (e.g., at least substantially dried stream 134) fromwater removal assembly 128, to produce one or more intermediate streams162 or one or more methane-rich streams 64 containing a lowerconcentration of carbon oxide gas and hydrogen gas and/or a higherconcentration of methane gas compared to the at least substantiallydried stream(s). The gas removal reactor may produce the intermediateand/or methane-rich stream(s) via any suitable mechanism(s). Forexample, gas removal reactor 156 may generate those streams via amethanation reaction. When gas removal reactor 156 generatesintermediate stream 162 and/or methane-rich stream 64 via a methanationreaction, that reactor may sometimes be referred to as a “methanationreactor,” “synthetic natural gas reactor” or “SNG reactor.”

The SNG reactor(s) may be operated between 250° C. and 450° C., andpreferably between 290° C. and 380° C. Additionally, the operatingpressure of the SNG reactor may be similar to the operating pressure ofthe HHR reactor, such as with only a minimal pressure drop between theHHR reactor and the SNG reactor. For example, the HHR reactor mayoperate between 20 psig to 100 psig and the SNG reactor may operatebetween 18 psig to 98 psig, which assumes a 2 psig pressure drop(reduction) due to components located between the two reactors (such asthe heat exchanger and the gas dryer).

Gas removal reactor 156 may have any suitable design, such as a tubularor cylindrical design. Additionally, gas removal reactor 156 may includeany suitable catalyst-containing bed or region to accelerate chemicalreaction or conversion rates. When the gas removal mechanism ismethanation, the gas removal reactor may include a suitable methanationcatalyst 166 to facilitate production of intermediate stream(s) 162and/or methane-rich stream(s) 64 from at least substantially driedstream(s) 160. Examples of suitable methanation catalysts includenickel-based catalysts (such as Reformax® RS-100 and HyProGen® R-70,both sold by Clariant, Louisville, Ky.; and MC-750R sold by Unicat,Houston, Tex.) and ruthenium-based catalysts (such as M-10 sold byClariant, Louisville, Ky.).

Gas removal reactor 156 may be configured to convert a portion of carbonoxide gas and/or a portion of hydrogen gas in at least substantiallydried stream 160 to methane gas and water. As an example, gas removalreactor 156 may be configured to convert carbon dioxide gas and hydrogengas to methane gas and water as shown in the approximate chemicalreaction below.CO₂+4H₂→CH₄+2H₂OAs another example, gas removal reactor 156 may be configured to convertcarbon monoxide gas and hydrogen gas to methane gas and water as shownin the approximate chemical reaction below.CO+3H₂→CH₄+H₂OThe above equations are only examples and do not represent all theconversions and/or reactions that may occur in the gas removal reactor.

Gas removal assembly 156 may include two or more gas removal reactors156, such as in series or in parallel, to remove carbon oxide gas and/orhydrogen gas. In some embodiments, a water removal assembly may beupstream one or more gas removal reactors 156. In some embodiments, awater removal assembly may be upstream each gas removal reactor 156.

Gas removal assembly 154 also may include a temperature modulatingassembly in the form of heating assembly 158. The heating assembly maybe configured to produce at least one heated exhaust stream (orcombustion stream) 168 from at least one heating fuel stream 170,typically as combusted in the presence of air. Heated exhaust stream 168is schematically illustrated in FIG. 8 as heating gas removal reactor156. Heating assembly 158 may include any suitable structure configuredto generate the heated exhaust stream, such as a burner or combustioncatalyst in which a fuel is combusted with air to produce the heatedexhaust stream. The heating assembly may include an ignitor or ignitionsource 172 that is configured to initiate the combustion of fuel.

Heating assembly 158 may achieve and/or maintain any suitabletemperatures in gas removal reactor 156. For example, heating assembly158 may heat the gas removal reactor to at least a target operatingtemperature and/or at least a minimum conversion temperature. When gasremoval reactor 156 removes gases via a methanation reaction (which isan exothermic reaction), the heat assembly may initially heat gasremoval reactor to a target operating temperature and then only asnecessary to maintain the gas removal reactor at a target operatingtemperature (such as because of heat loss, etc.).

In some embodiments, heating assembly 158 may include a burner assembly174 and may be configured to receive at least one fuel stream 170 and tocombust the fuel stream in the presence of air to provide one or morehot combustion streams 168 that may be used to heat the gas removalreactor. Air may be delivered to the heating assembly via a variety ofmechanisms. For example, at least one air stream 176 may be delivered tothe heating assembly as a separate stream, as shown in FIG. 8.Alternatively, or additionally, air stream 176 may be delivered to theheating assembly with at least one of the fuel streams 170 for heatingassembly 158 and/or drawn from the environment within which the heatingassembly is utilized.

Fuel stream 170 may include any combustible liquid(s) and/or gas(es)that are suitable for being consumed by heating assembly 158 to providethe desired heat output. In some embodiments, feedstock delivery system36 may provide one or more fuel streams 170. Some fuel streams may begases when delivered and combusted by heating assembly 158, while othersmay be delivered to the heating assembly as a liquid stream. Examples ofsuitable heating fuels for fuel streams 158 include carbon-containingfeedstocks, low molecular weight condensable fuels, and low molecularweight hydrocarbons. Other examples include hydrogen gas and carbonoxide gas from byproduct stream(s) 178s. For example, one or morebyproduct streams 178 from other components and/or assemblies of thefuel processing system may be used as a suitable heating fuel for fuelstream(s) 170.

Combustion stream(s) 168 may additionally, or alternatively, be used toheat other portions of the fuel processing system and/or other systemswith which the heating assembly is used. After combustion stream 168heats gas removal reactor 156 and/or other components and assemblies,the stream(s) may exit as combustion exhaust stream(s) 180.

Additionally, other configurations and types of heating assemblies 158may be used. For example, heating assembly 158 may be an electricallypowered heating assembly that is configured to heat gas removal reactor156 by generating heat using at least one heating element (such as aresistive heating element), waste heat stream(s), solar heating, etc. Inthose embodiments, heating assembly 158 may not receive and combust acombustible fuel stream to heat gas removal reactor 156 to a suitablegas-removal temperature.

The heating assembly also may be configured to heat other componentsand/or assemblies, such as the feedstock delivery system, the feedstocksupply streams, methane-producing assemblies, and/or other assemblies ofthe purification assembly, or any suitable combination of those systems,streams, and regions. The heating assembly may additionally beconfigured to heat other components of the refining assembly. Forexample, the heated exhaust stream may be configured to heat a pressurevessel and/or other canister containing the heating fuel and/or thehydrogen-production fluid that forms at least portions of the feedstream(s) and/or fuel stream(s).

Heating assembly 158 may be housed in an assembly shell or housing withthe gas removal reactor. The heating assembly may be separatelypositioned relative to the gas removal reactor but in thermal and/orfluid communication with that component to provide the desired heating.Heating assembly 158 may be located partially or completely within thecommon shell, and/or at least a portion (or all) of the heating assemblymay be located external that shell. When the heating assembly is locatedexternal the shell, the hot combustion gases from burner assembly 174may be delivered via suitable heat transfer conduits to one or morecomponents within the shell.

Although gas removal assembly 154 and methane-producing assembly 94 (inFIG. 2) are shown to each include a heating assembly, the gas removaland methane-producing assemblies may have a common heating assembly thatmay be located within the shell of the methane-producing assembly,within the shell of the gas removal assembly, or outside one or boththose shells. When there is a common heating assembly between the gasremoval assembly and the methane-producing assembly, the heatingassembly may include suitable heat transfer conduits to transfer heat tothe components of the gas removal and/or methane-producing assemblies.Additionally, when gas removal assembly 154 includes two or more gasremoval reactors 156, the gas removal assembly may include a commonheating assembly 158 for two or more of the gas removal reactors (and,in some embodiments, for all of the gas removal reactors). Moreover,although gas removal assembly 154 is shown to include a single gasremoval reactor 156 and a single heating assembly 158, the gas removalassembly may include two or more gas removal reactors 156 and/or two ormore heating assemblies 158, as shown in dashed lines in FIG. 8.

Gas removal reactor 156 and heating assembly 158 may be arranged in anysuitable configuration. Examples of suitable configurations are shown inFIGS. 9-10. In FIG. 9, gas removal reactor 156 is disposed above heatingassembly 158. In FIG. 10, heating assembly 158 is spaced from andadjacent to gas removal reactor 156.

Another example of a gas removal assembly 130 is shown in FIG. 11, whichis generally indicated at 184. Unless specifically excluded, gas removalassembly 184 may include one or more components of other gas removalassemblies described in this disclosure. Gas removal assembly 184 mayinclude at least one gas separation assembly 186.

Gas separation assembly 186 may include any suitable structureconfigured to separate carbon oxide gas and/or hydrogen gas from an atleast substantially dried stream 188 (such as from an upstream waterremoval assembly) and/or from an intermediate stream 189 (such as froman upstream gas removal reactor) to produce a methane-rich stream 190(e.g., methane-rich stream 64), or intermediate stream 192 if there areadditional gas removal assemblies downstream, having a reducedconcentration of carbon oxide gas and/or hydrogen gas and/or anincreased concentration of methane gas compared to streams 188 and/or189. For example, gas separation assembly 186 may include at least oneabsorber 194 configured to receive at least one chemical agent orabsorbent 196 that is adapted to absorb, via reversible chemical bindingand/or physical dissolution, at least a portion of carbon oxide gasand/or hydrogen gas from at least substantially dried stream 190 and/orfrom intermediate stream 192.

The absorber is configured to receive absorbent 196 and direct flow ofstreams 188 and/or 189 through the absorbent to absorb carbon oxide gasand/or hydrogen gas from those streams. As used herein, “absorb” meansthat carbon oxide gas and/or hydrogen gas is bound to or fixed by theabsorbent through a reversible or irreversible process, including weakchemical binding and/or physical solvation, and the bound carbon oxidegas and/or hydrogen gas may involve surface interactions with theabsorbent, bulk interactions with the absorbent, or both. Absorbent 196may be in liquid form, in solid form, or a combination. Suitableexamples of absorbents for carbon oxide include any chemical or mix ofchemicals that bind carbon oxide, such as metal hydroxides (e.g., sodiumhydroxide, potassium hydroxide, calcium hydroxide, magnesium hydroxide,etc.); metal oxides (e.g., sodium oxide, potassium oxide, calcium oxide,magnesium oxide, iron oxide, etc.); organic amines, especiallyalkanolamines (e.g., monoethanolamine and diethanolamine, both liquidsunder normal conditions of temperature and pressure); UCARSOL®formulated solvents for acid-gas removal (manufactured and sold by DowChemical Company); aqueous solutions of metal hydroxides; Ascarite®(Thomas Scientific); CarboLime™ (Allied Health Products Inc.); SodaLime(Airgas Corp.); immobilized organic amines (such as organic amines boundto polymeric substrates, especially polymeric beads); dimethylpolyethyleneglycol, propylene carbonate, polyethylene glycol dialkylethers (e.g., Genosorb® 1753 sold by Clariant); organic ionic liquids;mixtures of the above chemicals and/or chemical agents; and other agentsor mixtures of agents that reversibly absorb carbon oxide by weakchemical interactions and/or physical dissolution.

Methane-rich stream 190 (or intermediate stream 192) leaving absorber194 may include a reduced concentration of carbon oxide gas and/orhydrogen gas and/or an increased concentration of methane gas comparedto at least substantially dried stream 188 and/or intermediate stream189. Preferably, the methane-rich stream includes less than 12% carbondioxide and especially preferred is less than 5% carbon dioxide.Absorber 194 may be operated at a pressure of less than 100 psig, andpreferably at a pressure that is between 10 psig and 50 psig.

When absorbent 196 is in solid form, absorber 194 may include two ormore absorbent beds 197 and may be configured to direct flow of streams188 and/or 189 to a first bed of those absorbent beds. When that bed isnearly saturated with carbon oxide gas and/or hydrogen gas, the absorbermay be configured to direct flow to another bed of the absorbent beds toallow the absorbent of the previous absorbent bed to be recharged and/orregenerated. When absorbent 196 is in liquid form, the absorbent may beconfigured to absorb or bind carbon oxide gas and/or hydrogen gas atrelatively low temperatures and then release or desorb the gas(es) atelevated temperatures.

Gas separation assembly 186 may alternatively, or additionally, includea membrane contactor assembly 198 that may include one or more permeablemembranes 200 (such as one or more carbon oxide-selective membranes).The membrane contactor assembly 198 may be configured to separate carbonoxide gas and/or hydrogen gas from at least substantially dried stream188 and/or from intermediate stream 189. For example, permeablemembranes 200 may have relatively high permeability to carbon oxide gasand/or hydrogen gas relative to methane gas allowing carbon oxide gasand/or hydrogen from streams 190 and/or 192 to pass from a feed side toa permeate side of the permeable membranes.

Membrane contactor assembly 198 may additionally be configured toreceive at least one liquid chemical agent or liquid absorbent 202 thatis adapted to absorb at least a portion of carbon oxide gas and/orhydrogen gas from the carbon oxide gas and/or hydrogen gas separatedfrom streams 188 and/or 189 (such as the carbon oxide gas and/orhydrogen gas that passes from the feed side to the permeate side of thepermeable membranes). For example, the membrane contactor assembly mayreceive the absorbent on the permeate side of permeable membranes 200.Liquid absorbent 202 may be configured to absorb or bind carbon oxidegas and/or hydrogen gas at relatively low temperatures and then releaseor desorb the gas(es) at elevated temperatures. Examples of suitableliquid absorbents include alkanolamines, such as monoethanolamine ordiethanolamine, or water solutions thereof. However, other organicamines, solutions of organic amines, or solutions of inorganic hydroxidesalts and/or organic hydroxide salts may be used.

When gas separation assembly 186 includes absorber(s) 194 and/orpermeable membrane(s) 200 that receive a liquid absorbent, the gasseparation assembly may produce at least one liquid absorbent stream 204having absorbed carbon oxide gas and/or hydrogen gas (which also may bereferred to as “spent liquid absorbent stream(s)” or “gas laden liquidabsorbent stream(s).” When spent liquid absorbent stream 204 is producedand the absorption of gas(es) in that stream is reversible, gas removalassembly 184 may additionally include at least one gas extractionassembly 206.

Gas extraction assembly 206 may include any suitable structureconfigured to extract (or desorb) the absorbed gases from liquidabsorbent stream(s) 204. For example, gas extraction assembly 206 mayinclude one or more strippers 208. In some embodiments, when the liquidabsorbent includes absorbed carbon oxide gas and/or hydrogen gas, thegas extraction assembly may be configured to extract or desorb at leasta substantial portion of the absorbed carbon oxide gas and/or hydrogengas to form an at least substantially regenerated liquid absorbentstream (or stripped liquid absorbent stream) 210 with at least asubstantial portion of the carbon oxide gas and/or hydrogen gasextracted, and an offgas stream 212 with the extracted carbon oxide gasand/or hydrogen gas.

Stripped liquid absorbent stream 210 may be pumped or otherwisetransported to gas separation assembly 186 to further absorb carbonoxide gas and/or hydrogen gas from streams 190 and/or 192.Alternatively, or additionally, stripped liquid absorbent stream 210 maybe stored for later use. Offgas stream 212 may be pumped or otherwisetransported to one or more other components of the refining assembly,such as to supplement one or more heating fuel streams. Alternatively,offgas stream 212 may be stored, exhausted into the air, or otherwisedisposed.

Gas extraction assembly 206 may use any suitable mechanism to regenerateliquid absorbent stream 204 having the absorbed gases. When the liquidabsorbent used in gas separation assembly 186 is configured to absorb orbind carbon oxide gas and/or hydrogen gas at relatively low temperaturesand then release or desorb the gas(es) at elevated temperatures, gasremoval assembly 184 may further include at least one heating assembly214. The heating assembly may be configured to produce at least oneheated exhaust stream (or combustion stream) 216 from at least oneheating fuel stream 218, typically as combusted in the presence of air.Heated exhaust stream 216 is schematically illustrated in FIG. 11 asheating gas extraction assembly 206. The heated exhaust stream mayalternatively, or additionally, heat spent liquid absorbent stream 204prior to gas extraction assembly 206, as shown in FIG. 11.

Heating assembly 214 may include any suitable structure configured togenerate the heated exhaust stream(s), such as a burner or combustioncatalyst in which a fuel is combusted with air to produce the heatedexhaust stream(s). The heating assembly may include an ignitor orignition source 220 that is configured to initiate the combustion offuel. Heating assembly 214 may achieve and/or maintain in gas extractionassembly 206 and/or piping prior to that assembly any suitabletemperatures. For example, heating assembly 214 may heat the gasextraction assembly to at least a target operating temperature and/or atleast a minimum extraction or desorption temperature for the particularliquid absorbent used.

In some embodiments, heating assembly 214 may include a burner assembly222 and may be configured to receive at least one fuel stream 218 and tocombust the fuel stream in the presence of air to provide a hotcombustion stream 216 that may be used to heat the gas removal reactor.Air may be delivered to the heating assembly via a variety ofmechanisms. For example, an air stream 224 may be delivered to theheating assembly as a separate stream, as shown in FIG. 11.Alternatively, or additionally, air stream 224 may be delivered to theheating assembly with at least one of the fuel streams 218 for heatingassembly 214 and/or drawn from the environment within which the heatingassembly is utilized.

Fuel stream 218 may include any combustible liquid(s) and/or gas(es)that are suitable for being consumed by heating assembly 214 to providethe desired heat output. Some fuel streams may be gases when deliveredand combusted by heating assembly 214, while others may be delivered tothe heating assembly as a liquid stream. Examples of suitable heatingfuels for fuel streams 218 include carbon-containing feedstocks, lowmolecular weight condensable fuels, and low molecular weighthydrocarbons. Other examples include hydrogen gas and/or carbon oxidegas from one or more byproduct streams 226. For example, one or morebyproduct streams 226 from other components and/or assemblies of thefuel processing system may be used as a suitable heating fuel for fuelstream 218.

Combustion stream 216 may additionally, or alternatively, be used toheat other portions of the fuel processing system and/or other systemswith which the heating assembly is used. Additionally, otherconfiguration and types of heating assemblies 214 may be used. Forexample, heating assembly 214 may be an electrically powered heatingassembly that is configured to heat gas extraction assembly 206 and/orpiping upstream of that assembly by generating heat using at least oneheating element (such as a resistive heating element), waste heatstream(s), solar heating, electric heating, etc. In those embodiments,heating assembly 214 may not receive and combust a combustible fuelstream to heat vaporizer to a suitable vaporization temperature and/orheat methane-producing reactor to a suitable methane-producingtemperature.

The heating assembly also may be configured to heat other componentsand/or assemblies, such as a feedstock delivery system, the feedstocksupply streams, methane-producing assemblies, and/or other assemblies ofthe purification assembly, or any suitable combination of those systems,streams, and regions. The heating assembly may additionally beconfigured to heat other components of the refining assembly. Forexample, the heated exhaust stream may be configured to heat a pressurevessel and/or other canister containing the heating fuel and/or thehydrogen-production fluid that forms at least portions of the feedand/or fuel streams for the fuel processing system.

Heating assembly 214 may be housed in an assembly shell or housing 226with the gas separation and gas extraction assemblies. The heatingassembly may be separately positioned relative to one or both of thoseassemblies but in thermal and/or fluid communication with one or both toprovide the desired heating. Heating assembly 214 may be locatedpartially or completely within the common shell, and/or at least aportion (or all) of the heating assembly may be located external thatshell. When the heating assembly is located external the shell, the hotcombustion gases from burner assembly 222 may be delivered via suitableheat transfer conduits to one or more components within the shell.

Although gas removal assembly 184 (in FIG. 11), gas removal assembly 154(FIG. 8), and methane-producing assembly 94 (in FIG. 2) are shown toeach include a heating assembly, gas removal assembly 184, gas removalassembly 154, and/or methane-producing assembly 94 may have a commonheating assembly that may be located within the shell of themethane-producing assembly, within the shell of one or more of the gasremoval assemblies, or outside those shells. When there is a commonheating assembly between the gas removal assemblies and themethane-producing assembly, the heating assembly may include suitableheat transfer conduits to transfer heat to the components of the gasremoval and/or methane-producing assemblies. Additionally, when gasextraction assembly 206 includes two or more strippers 208, the gasextraction assembly may include a common heating assembly 214 for two ormore of the strippers (and, in some embodiments, for all of thestrippers). Moreover, although gas removal assembly 184 is shown toinclude a single gas separation assembly 186, a single gas extractionassembly 206, and a single heating assembly 214, the gas removalassembly may include two or more gas separation assemblies, two or moregas extraction assemblies, and/or two or more heating assemblies, asshown in dashed lines in FIG. 11.

Another example of refining assembly 30 is shown in FIG. 12, which isgenerally indicated at 230. Unless specifically excluded, refiningassembly 230 may include one or more components of the other refiningassemblies and/or other assemblies in this disclosure. Refining assembly230 may include a feedstock delivery system 232 and a fuel processingsystem 234.

Feedstock delivery system 232 may include any suitable structureconfigured to deliver one or more feed and/or fuel streams to one ormore other components of refining assembly 230. For example, thefeedstock delivery system may include a water source 236, a rich naturalgas source 238, and a pump 240. The water source may be a storage tank,a storage container, a water reservoir, a natural body of water, etc.configured to provide a water stream 242 (such as a deionized waterstream) to fuel processing system 234. Rich natural gas source 238 maybe a wellhead, a storage tank, a storage container, a desulfurizationassembly, etc. configured to provide a rich natural gas stream 244 tofuel processing system. Pump 240 may have any suitable structureconfigured to deliver or transport the water to fuel processing system234. The rich natural gas stream 244 may combine with water stream 242to form at least one liquid-containing feed stream 246. Alternatively,or additionally, the rich natural gas stream may be delivered ortransported to fuel processing system 234 and combine with the waterstream at the fuel processing system. In some embodiments, feedstockdelivery system 232 may include one or more additional pumps and/orcompressors to deliver or transport rich natural gas stream 244 tocombine with water stream 242 and/or to fuel processing system 234.

Fuel processing system 234 may include any suitable structure configuredto process rich natural gas stream(s) 244, such as to increaseconcentration of methane gas and/or reduce concentration of othercomponents in the rich natural gas stream. For example, fuel processingsystem 234 may include at least one methane-producing assembly 248, aheat exchange assembly 250, a water removal assembly 252, a first gasremoval assembly 254, and a second gas removal assembly 258.Methane-producing assembly 248 may include any suitable structureconfigured to receive liquid-containing feed stream(s) 246 (or waterstream(s) 242 and rich natural gas stream(s) 244) and produce an outputstream 260 containing methane gas as the primary component but alsocontaining water and other gases. For example, methane-producingassembly 248 may include at least one vaporization region or vaporizer262, at least one methane-producing region or reactor 264, and at leastone heating assembly 266, as shown in FIG. 13.

Vaporizer 262 may include any suitable structure configured to receiveand vaporize at least a portion of a liquid-containing feed stream, suchas liquid-containing feed stream 246. For example, vaporizer 262 may beconfigured to at least partially transform liquid-containing feed stream246 into one or more at least substantially vaporized streams 268. Theat least substantially vaporized streams may, in some embodiments,include liquid(s). An example of a suitable vaporizer is a coiled tubevaporizer, such as a coiled stainless steel tube.

Methane-producing reactor 264 may include any suitable structureconfigured to receive one or more feed streams, such as at leastsubstantially vaporized stream(s) 268 from the vaporizer, to produce oneor more output streams 260 containing methane gas as a majoritycomponent, water, and other gases. The methane-producing reactor mayproduce the output stream via any suitable mechanism(s). For example,methane-producing reactor 264 may generate output stream(s) 260 via aheavy hydrocarbon reforming reaction. In that example, methane-producingreactor 264 may include a catalyst 270 configured to facilitate and/orpromote the heavy hydrocarbon reforming reaction. When methane-producingreactor 264 generates output stream(s) 260 via a heavy hydrocarbonreforming reaction, methane-producing reactor may be referred to as a“heavy hydrocarbon reforming reactor” or “HHR reactor,” and outputstream 260 may be referred to as a “reformate stream.”

Heating assembly 266 may include any suitable structure configured toproduce at least one heated exhaust stream 272 for heating one or moreother components of the methane-producing assembly. For example, theheating assembly may heat the vaporizer to any suitable temperature(s),such as at least a minimum vaporization temperature or the temperaturein which at least a portion of the liquid-containing feed stream isvaporized to form the at least substantially vaporized stream.Additionally, or alternatively, heating assembly 266 may heat themethane-producing reactor to any suitable temperature(s), such as atleast a minimum methane-producing temperature or the temperature inwhich at least a portion of the vaporized feed stream is reacted toproduce methane gas to form the output stream. The heating assembly maybe in thermal communication with one or more other components of themethane-producing assembly, such as the vaporizer and/ormethane-producing reactor.

The heating assembly may include a burner assembly 274, at least one airblower 276, and an igniter assembly 278, as shown in FIG. 13. The burnerassembly may include any suitable structure configured to receive atleast one air stream 280 and at least one fuel stream 282 and to combustthe at least one fuel stream to produce heated exhaust stream(s) 272.The fuel stream may be provided by feedstock delivery system 232 and/orone or more of the gas removal assemblies. For example, one or more gasremoval assemblies that remove carbon oxide gas and/or hydrogen gas maysend those gases to burner assembly 274 as a byproduct fuel stream 283.

Fuel streams 282 and/or 283 may be delivered to burner assembly 274 viaa pump 284 and/or other suitable device. If fuel streams 282 and/or 283are available at sufficient pressure, pump 284 may not be necessary andmay be excluded. Although pump 284 is shown to transport fuel stream 282and not byproduct fuel stream 283 to burner assembly 274, the pump mayalternatively, or additionally, transport byproduct fuel stream 283 toburner assembly 274, or one or more other pumps may transport thebyproduct fuel stream to the burner assembly. Diaphragm and pistonpumping mechanisms are examples of suitable pumps for use as pump 284,although other types of pumps and compressors may be used. Air blower276 may include any suitable structure configured to generate airstream(s) 280. Igniter assembly 278 may include any suitable structureconfigured to ignite fuel stream(s) 282 and/or 283. Althoughmethane-producing assembly 248 is shown to include a single vaporizer262, a single methane-producing reactor 264, and a single heatingassembly 266, the methane-producing assembly may include two or morevaporizers 262, two or more methane-producing reactors 264, and/or twoor more heating assemblies 266, as shown in dashed lines in FIG. 13.

In some embodiments, methane-producing assembly 248 may include a shellor housing 285 which may at least partially contain one or more othercomponents of that assembly. For example, shell 285 may at leastpartially contain vaporizer 262, methane-producing reactor 264, and/orheating assembly 266, as shown in FIG. 13. Shell 285 may include one ormore exhaust ports 286 configured to discharge at least one combustionexhaust stream 287 produced by heating assembly 266. The shell orhousing may include insulation and/or a jacket.

Referring back to FIG. 12, heat exchange assembly 250 may include one ormore heat exchangers configured to transfer heat from one portion of therefining assembly to one or more other portion(s). For example, heatexchange assembly 250 may include a first heat exchanger 288 and asecond heat exchanger 289. The first heat exchanger may be configured totransfer heat from output stream 260 to an at least substantially driedstream 290 exiting water removal assembly 252 to raise the temperatureof the substantially dried stream prior to gas removal assembly 254, aswell as to cool output stream 260 prior to water removal assembly 252.Second heat exchanger 289 may be configured to cool an intermediatestream 292 exiting an upstream gas removal assembly (such as first gasremoval assembly 254) prior to another gas removal assembly (such assecond gas removal assembly 258). For example, second heat exchanger 289may cool intermediate stream 292 to less than or equal to 100° C., andpreferably less than or equal to 50° C. In some embodiments, heatexchange assembly 250 may include one or more fans 294 to cool one ormore streams passing through the first and/or second heat exchangers.Although second heat exchanger 289 is shown to receive only the coolingstream(s) from fan(s) 294, that heat exchanger may alternatively, oradditionally, receive one or more other cooling fluid streams (such asfrom one or more other portions or components of the refining assembly)

Water removal assembly 252 may include any suitable structure configuredto remove water from output stream 260 to produce at least substantiallydried stream 290. For example, water removal assembly 252 may include atleast one gas dryer 296 configured to remove at least a substantialportion of water vapor from output stream 260 and to form at least onereclaimed water stream 298 from the removed water vapor. In someembodiments, the water removal assembly may include at least one waterknockout device 299 configured to remove at least a substantial portionof liquid water from output stream 260. When refining assembly 230includes one or more water knockout device(s) 299, those devices may beimmediately upstream of (or immediately prior to) the gas dryer(s) andmay produce at least a portion of reclaimed water stream 298 from theremoved water. In some embodiments, water removal assembly 252 mayinclude a reclaimed water pump 300 configured to move or transport thereclaimed water stream to feedstock delivery system 232, such as to addor supplement water to water source 236. The reclaimed water stream(s)also may be sent to one or more other components of refining assembly230, sent to drain, and/or otherwise disposed.

First gas removal assembly 254 may include any suitable structureconfigured to remove one or more other gases (such as gas(es) other thanmethane gas) from one or more streams, such as at least substantiallydried stream(s) 290, and to produce one or more intermediate streams 292having a lower concentration of the other gases and/or a higherconcentration of methane gas. In some embodiments, intermediatestream(s) 292 may include less than 5% hydrogen gas, and preferably lessthan 3% hydrogen gas; and less than 15% carbon dioxide. For example,first gas removal assembly 254 may include at least one gas removalregion or reactor 302 and at least one heating assembly 304, as shown inFIG. 14.

Gas removal reactor 302 may include any suitable structure configured toreceive one or more at least substantially dried streams 290, and toproduce one or more intermediate streams 292. The gas removal reactormay produce the intermediate stream via any suitable mechanism(s). Forexample, gas removal reactor 302 may generate intermediate stream(s) 292via a methanation reaction. In that example, gas removal reactor 302 mayinclude a catalyst 306 configured to facilitate and/or promote themethanation reaction. When gas removal reactor 302 generatesintermediate stream(s) 292 via a methanation reaction, the gas removalreactor may be referred to as a “synthetic natural gas reactor” or “SNGreactor.”

Heating assembly 304 may include any suitable structure configured toproduce at least one heated exhaust stream 308 for heating one or moreother components of the gas removal assembly. For example, the heatingassembly may heat the gas removal reactor to any suitabletemperature(s), such as at least a minimum methanation or thetemperature in which at least a portion of the carbon oxide gas andhydrogen gas in the at least substantially dried stream is reacted toproduce methane gas and water to form the intermediate stream. Theheating assembly may be in thermal communication with one or more othercomponents of the gas removal assembly, such as the gas removal reactor.

The heating assembly may include a burner assembly 310, at least one airblower 312, and an igniter assembly 314, as shown in FIG. 14. The burnerassembly may include any suitable structure configured to receive atleast one air stream 316 and at least one fuel stream 318 and to combustthe at least one fuel stream to produce heated exhaust stream(s) 308.The fuel stream may be provided by feedstock delivery system 232 and/orone or more other gas removal assemblies. For example, one or more gasremoval assemblies that remove carbon oxide gas and/or hydrogen gas maysend those gases to burner assembly 310 as a byproduct fuel stream 320.

Fuel streams 318 and/or 320 may be delivered to burner assembly 310 viaone or more pumps 324 and/or other suitable device. If fuel streams 318and/or 320 are available at sufficient pressure, pump 324 may not benecessary and may be excluded. Although pump 324 is shown to transportfuel stream 318 and not byproduct stream 320 to burner assembly 310, thepump may alternatively, or additionally, transport byproduct fuel stream320 to burner assembly 310, or one or more other pumps may transport thebyproduct fuel stream to the burner assembly. Diaphragm and pistonpumping mechanisms are examples of suitable pumps for use as pump 324,although other types of pumps and compressors may be used. Air blower312 may include any suitable structure configured to generate airstream(s) 316. Igniter assembly 314 may include any suitable structureconfigured to ignite stream(s) 318 and/or 320. Although gas removalassembly 254 is shown to include a single gas removal reactor 302 and asingle heating assembly 304, the gas removal assembly may include two ormore gas removal reactors 302 and/or two or more heating assemblies 304,as shown in dashed lines in FIG. 14.

In some embodiments, gas removal assembly 254 may include a shell orhousing 326 which may at least partially contain one or more othercomponents of that assembly. For example, shell 326 may at leastpartially contain gas removal reactor 302 and/or heating assembly 304,as shown in FIG. 14. Shell 326 may include one or more exhaust ports 328configured to discharge at least one combustion exhaust stream 330produced by heating assembly 304. Shell or housing 326 may includeinsulation and/or a jacket.

Intermediate stream 292 is predominantly methane with less than 15%carbon oxide and less than 5% hydrogen. For some applications, such ascombustion in an engine, intermediate stream 92 may be sufficiently richin methane, and sufficiently depleted in carbon oxides and hydrogen, asto be suitable without further processing. In this case, additional gasremoval assembly(ies), such as second gas removal assembly 258, may beexcluded.

Referring back to FIG. 12, refining assembly 230 may, in someembodiments, include one or more additional heat exchangers 334, one ormore additional water removal assemblies 336 (having one or more pumps337 for transporting reclaimed water to the feedstock delivery system),and one or more additional gas removal assemblies 338. Water removalassemblies 336 and/or gas removal assemblies 338 may be the same ordifferent from water removal assembly 252 and first gas removal assembly254, respectively. For example, water removal assembly 336 may include agas dryer. Additionally, gas removal assembly 338 may include a gasremoval reactor, such as a SNG reactor. Alternatively, gas removalassembly 338 may include one or more components of second gas removalassembly 258 described below. Although only a single heat exchanger 334,a single water removal assembly 336, and a single gas removal assembly338 is shown in FIG. 12, refining assembly 230 may include additionalheat exchangers, water removal assemblies, and gas removal assemblies,which may be in series and/or in parallel with heat exchanger 334, waterremoval assembly 336, and gas removal assembly 338. The additional waterremoval assemblies and gas removal assemblies may be the same ordifferent from water removal assembly 336 and gas removal assembly 338,respectively.

Second gas removal assembly 258 may include any suitable structureconfigured to remove one or more other gases (such as gas(es) other thanmethane gas) from one or more streams, such as intermediate stream(s)292 to form at least one methane-rich stream 332, which may include agreater methane concentration than intermediate stream(s) 292 and/or areduced concentration of one or more other gases (or impurities) thatwere present in the intermediate stream(s). In some embodiments, thesecond gas removal assembly may form at least one byproduct stream 333with the removed gases. Examples of second gas removal assemblies 258are described below.

Refining assembly 230 may, in some embodiments, include a control system340, which may include any suitable structure configured to controland/or monitor operation of the refining assembly. For example, controlsystem 340 may include a control assembly 342, one or more flowmeasurement devices 344, one or more temperature measurement devices346, and one or more control valves 348, as shown in FIGS. 12-13.

Control assembly 342 may detect flow rate of rich natural gas stream 244and adjust delivery (such as the flow rate) of water stream 242 based,at least in part, on the detected flow rate. Additionally, controlassembly 342 may detect temperatures in the methane-producing reactorand/or gas removal reactor via temperature measurement devices 346 (suchas thermocouples and/or other suitable devices) and adjust flow rate ofthe fuel stream(s) and/or byproduct fuel stream(s) via control valves348 and/or adjust flow rate of the air stream(s) by controlling speed ofthe air blower(s), based, at least in part, on the detectedtemperature(s). For example, control assembly 342 may increase flow rateof the fuel stream(s) and/or byproduct fuel stream(s) via controlvalve(s) 348, if the detected temperature is lower than a minimumtemperature (such as a minimum methane-producing temperature or aminimum gas removal temperature). Additionally, control assembly 342 maydecrease flow rate of the fuel stream(s) and/or byproduct fuel stream(s)via control valve(s) 348 and/or increase the speed of the air blower(s),if the detected temperature is higher than a maximum temperature (suchas a maximum methane-producing temperature or a maximum gas removaltemperature).

In some embodiments, control system 340 may include one or more othermeasurement devices, such as to measure sulfur breakthrough in the richnatural gas stream, conductivity (or resistivity) of the deionized waterin the water stream, pump motor speed(s), pump discharge flow rate(s),operating temperature(s), operating pressure(s), etc. Control assembly342 may provide early warning of a impending need for maintenance based,at least in part, on one or more measurement devices. In someembodiments, control system 340 may provide for remote monitoring andcontrol of one or more components of refining assembly 230.

An example of second gas removal assembly 258 is shown in FIG. 15, whichis generally indicated at 350. Unless specifically excluded, second gasremoval assembly 258 may include one or more components of the other gasremoval assemblies and/or other assemblies in this disclosure. Gasremoval assembly 350 may include at least one absorber 352, at least onestripper 354, at least one heating assembly 356, at least one pump 358,and at least one heat exchanger 360.

Absorber 352 may include any suitable structure configured to receive aliquid absorbent stream 362 that is adapted to absorb at least a portionof carbon oxide gas and/or hydrogen gas from one or more streams, suchas intermediate stream(s) 292, and/or to direct flow of those streams(such as intermediate stream 292) through the liquid absorbent stream.For example, absorber 352 may include at least one spray nozzle 364configured to at least partially atomize the liquid absorbent streaminto one or more sprayed liquid absorbent streams 366. The absorber maybe configured to direct flow of intermediate stream(s) 292 throughsprayed liquid absorbent stream(s) 366 in any suitable flowconfiguration, such as counter-current flow, cross-current flow, orparallel flow. As intermediate stream(s) 292 flows through the sprayedliquid absorbent stream(s), carbon oxide gas and/or hydrogen gas may, atleast partially, be absorbed by the sprayed stream(s) to formmethane-rich stream 332 without the absorbed carbon oxide gas and/orhydrogen gas and a spent liquid absorbent stream 368 having the absorbedcarbon oxide gas and/or hydrogen gas. Absorber 352 may be operated at apressure of less than 100 psig, and preferably at a pressure between 10psig and 50 psig.

Although FIG. 15 shows absorber 352 with spray nozzle(s) 364, anothersuitable configuration is to return liquid absorbent stream 362 withoutusing a spray nozzle. For example, liquid absorbent stream 362 may entera top, middle, or bottom portion of absorber 352 through a suitable tubeor pipe connection, and the liquid absorbent may be allowed toaccumulate a fill a volume at the bottom of the absorber. Intermediatestream 292 may be directed to bubble up through the volume of the liquidabsorbent to remove at least a portion of carbon oxide gas and/orhydrogen gas to form methane-rich stream 332.

Stripper 354 may include any suitable structure configured to receiveone or more spent liquid absorbent streams 368, strip the absorbedcarbon oxide gas and/or hydrogen gas from those stream(s), and/ordeliver one or more stripped liquid absorbent streams 370 to absorber(s)352. For example, stripper 354 may include at least one spray nozzle 372configured to at least partially atomize the spent liquid absorbentstream into one or more sprayed spent liquid absorbent streams 374.Stripper 354 may strip the absorbed carbon oxide gas and/or hydrogen gasvia any suitable mechanism(s). For example, when the liquid absorbent(s)used for liquid absorbent stream 362 absorbs or binds carbon oxide gasand/or hydrogen gas within a first temperature range and releases ordesorbs carbon oxide gas and/or hydrogen gas within a second temperaturerange higher than the first temperature range, then stripper 354 may beconfigured to receive one or more heated exhaust streams 376 fromheating assembly 356 and direct the flow of those streams through thesprayed spent liquid absorbent stream(s).

For example, the sprayed spent liquid stream(s) may be heated by theheated exhaust stream(s) between 60° C. and 200° C., and preferablybetween 80° C. and 150° C., to drive off the absorbed carbon oxide gasand/or hydrogen gas to produce or yield at least substantiallyregenerated liquid absorbent stream 370. The released of desorbed gassesmay form at least one offgas stream 377. Stripper 354 may be operatedwithin the range of 0 psig and 50 psig, and preferably 0 psig and 10psig.

Heating assembly 356 may include any suitable structure configured toproduce at least one heated exhaust stream 376 for heating sprayed spentliquid absorbent stream(s) 374. For example, the heating assembly mayheat the stripper to any suitable temperature(s), such as at least aminimum release or desorption temperature for the carbon oxide gasand/or hydrogen gas in the sprayed spent liquid absorbent stream(s).

The heating assembly may include a burner assembly 378, at least one airblower 380, and an igniter assembly 382, as shown in FIG. 15. The burnerassembly may include any suitable structure configured to receive atleast one air stream 384 and at least one fuel stream 386 and to combustthe at least one fuel stream to produce heated exhaust stream(s) 376.The fuel stream may be provided by feedstock delivery system 232 and/orone or more of the gas removal assemblies. For example, one or more gasremoval assemblies that remove carbon oxide gas and/or hydrogen gas maysend those gases to burner assembly 378 as a byproduct fuel stream 388.Additionally, at least a portion of offgas stream 377 may be used asthat byproduct fuel stream. Fuel streams 386 and/or 388 may be deliveredto burner assembly 378 via a pump and/or other suitable device. Airblower 380 may include any suitable structure configured to generate airstream(s) 384. Igniter assembly 382 may include any suitable structureconfigured to ignite fuel stream(s) 386 and/or 388.

Additionally, other configuration and types of heating assemblies 356may be used. For example, heating assembly 356 may include at least oneheater 394 that is powered by at least one power assembly 396, as shownin FIG. 16. Heater 394 may include at least one heating element 398(such as a resistive heating element). The heating element may heatspent liquid absorbent stream 368 prior to stripper 354 (and/or spraynozzle 372) and/or may heat the spent liquid absorbent stream in thestripper. Power assembly 396 may include one or more electric cords (toallow a user to plug the heater into an electrical outlet), solarpanels, wind turbines, fuel cells, etc.

Pump 358 may include suitable structure configured to deliver ortransport stripped liquid absorbent stream(s) 370 to absorber 352 (suchas through spray nozzle 364 or a suitable tube or pipe connection) forabsorption of at least a portion of carbon oxide gas and/or hydrogen gasfrom intermediate stream(s) 292. Heat exchanger 360 may include anysuitable structure configured to transfer heat from the stripped liquidabsorbent stream(s) to the spent liquid absorbent stream(s).

In some embodiments, control system 340 may further include one or morefluid level measurement devices 390, as shown in FIG. 15. Controlassembly 342 may detect fluid level in absorber 352 and/or stripper 354via fluid level measurement devices 390, and control the speed of pump358 based, at least in part, on the detected fluid level(s). Forexample, control assembly 342 may reduce the speed of pump 358 (or theflow rate of stripped liquid absorbent stream 370) when fluid level inabsorber 342 is above a predetermined maximum level or the fluid levelin stripper 354 is below a predetermined minimum level. Additionally,control assembly 342 may increase the speed of pump 358 when fluid levelin absorber 342 is below a predetermined minimum level or the fluidlevel in stripper 354 is above a predetermined maximum level. Moreover,control assembly 342 may detect the temperature of spent liquidabsorbent stream 368 after that stream is heated by heater 394 (e.g.,prior to stripper 354 or in stripper 354) in FIG. 16 via temperaturemeasurement devices 346, and control the temperature setting and/orpower to the heater based, at least in part, on the detectedtemperature. For example, control assembly 342 may increase heatprovided by the heater if the detected temperature is below a minimumrelease temperature for the absorbed carbon oxide gas and/or hydrogengas.

In some embodiments, gas removal assembly 350 may include a shell orhousing 392 which may at least partially contain one or more othercomponents of that assembly. For example, shell 392 may at leastpartially contain absorber 352, stripper 354, heating assembly 356, pump358, and/or heat exchanger 360, as shown in FIGS. 15-16. The shell orhousing may include insulation and/or a jacket.

Another example of second gas removal assembly 258 is shown in FIG. 17,which is generally indicated at 400. Unless specifically excluded,second gas removal assembly 400 may include one or more components ofthe other gas removal assemblies in this disclosure. Second gas removalassembly 400 may include one or more absorbers 402 and control valves404.

Absorbers 402 may include at least one solid absorbent 406 (such as insolid absorbent beds) adapted to absorb at least a portion of carbonoxide gas and/or hydrogen gas from one or more streams, such asintermediate stream(s) 292, and/or to direct flow of those streamsthrough the solid absorbent. As intermediate stream(s) 292 flow throughthe solid absorbent, carbon oxide gas and/or hydrogen gas may, at leastpartially, be absorbed forming methane-rich stream 332 without theabsorbed carbon oxide gas and/or hydrogen gas. Second gas removalassembly 400 may include any suitable number of absorbers 402. Forexample, the second gas removal assembly may include a first absorber408 and a second absorber 410, as shown in FIG. 17. Although second gasremoval assembly 400 is shown to include two absorbers 402, the assemblymay include any suitable number of absorbers, such as one absorber orthree or more absorbers.

When second gas removal assembly 400 includes two or more absorbers 402,the second gas removal assembly may include two or more control valves404, which may include any suitable structure configured to isolate oneor more absorbers 402 and/or direct flow to one or more other absorbers402. For example, intermediate stream 292 may be directed to flowthrough first absorber 408 until the solid absorbent in that absorber issaturated or substantially saturated with carbon oxide gas and/orhydrogen gas. At that point, control valves 404 may isolate firstabsorber 408 and direct flow of intermediate stream 292 through secondabsorber 410 until the solid absorbent in the second absorber issaturated or substantially saturated. The solid absorbent in theisolated first absorber may be recharged or regenerated whileintermediate stream 292 is flowing through the second absorber, orvice-versa. In some embodiments, control valves 404 may be three-wayvalves directing flow of intermediate stream 292 to either the first orsecond absorbers and/or directing flow of methane-rich stream 332 fromeither the first or second absorbers.

In some embodiments, control system 340 may include one or moresaturation measurement devices 412. In those embodiments, controlassembly 342 may control operation of control valves 404 based, at leastin part, on the detected saturation. For example, control assembly 342may control the control valves to direct flow from a first absorber to asecond absorber when the first absorber is above a predetermined maximumsaturation level. In some embodiments, gas removal assembly 400 mayinclude a shell or housing 413 which may at least partially contain oneor more other components of that assembly. For example, shell 413 may atleast partially contain absorbers 402 and control valves 404, as shownin FIG. 17. The shell or housing may include insulation and/or a jacket.

Another example of second gas removal assembly 258 is shown in FIG. 18,which is generally indicated at 414. Unless specifically excluded,second gas removal assembly 414 may include one or more components ofthe other gas removal assemblies and/or other assemblies in thisdisclosure. Second gas removal assembly 414 may include a water removalassembly 416 and a membrane assembly 418.

Water removal assembly 416 may include any suitable structure configuredto remove water vapor and/or liquid water from one or more streams, suchas intermediate stream 292, to form an at least substantially driedstream 420. For example, water removal assembly 416 may include at leastone water knockout device 422 and/or at least one gas dryer 424. Waterremoved by water removal assembly 416 may form at least one reclaimedwater stream 426 that may be sent to feedstock delivery system 232and/or other components of refining assembly 230.

Membrane assembly 418 may include any suitable structure configured toseparate at least a portion of carbon oxide gas and/or hydrogen gas fromat least substantially dried stream 420 to form methane-rich stream 332.The separated carbon oxide gas and/or hydrogen gas may form byproductstream 333, which may be sent to feedstock delivery system 232, one ormore heating assemblies of other gas removal assemblies, and/or othercomponents of refining assembly 230. For example, membrane assembly 418may include one or more carbon oxide selective membranes 428 that areconfigured to separate at least a portion of carbon oxide gas and/orhydrogen gas from stream(s) 420. Membrane assembly 418 may include anysuitable number of membranes 428, as shown in dashed lines in FIG. 18.When membrane assembly 418 includes two or more membranes 428, thosemembranes may be arranged in parallel or in series. In some embodiments,gas removal assembly 414 may include a shell or housing 429 which may atleast partially contain one or more other components of that assembly.For example, shell 429 may at least partially contain membrane assembly418, as shown in FIG. 18. The shell or housing may include insulationand/or a jacket.

Another example of second gas removal assembly 258 is shown in FIG. 19,which is generally indicated at 430. Unless specifically excluded,second gas removal assembly 430 may include one or more components ofthe other gas removal assemblies and/or other assemblies in thisdisclosure. Second gas removal assembly 430 may include a water removalassembly 432, a membrane contactor assembly 434, at least one stripper436, at least one heating assembly 438, at least one heat exchanger 440,and at least one pump 442.

Water removal assembly 432 may include any suitable structure configuredto remove water vapor and/or liquid water from one or more streams, suchas intermediate stream 292, to form at least substantially dried stream444. For example, water removal assembly 432 may include at least onewater knockout device 446 and/or at least one gas dryer 448. Waterremoved by water removal assembly 432 may form at least one reclaimedwater stream 450 that may be sent to feedstock delivery system 232and/or other components of refining assembly 230.

Membrane contactor assembly 434 may include any suitable structureconfigured to separate carbon oxide gas and/or hydrogen gas from atleast substantially dried stream 444 to form methane-rich stream 332.For example, membrane contactor assembly 434 may include one or moremembrane contactors 452. Membrane contactor may include a plurality ofcarbon oxide selective membranes 454 that are configured to separate atleast a portion of carbon oxide gas and/or hydrogen gas from stream(s)444.

Membranes 454 may be hollow fiber or small-diameter tubular membranes,which may be sealed (or potted) into a shell 456, as shown in FIG. 20.Shell 456 may include inlet and outlet ports 457 and any suitable numberof membranes 454, such as hundreds to thousands of those membranes.Membranes 454 may have any suitable lengths, such as from about onecentimeter to about two to three meters, and/or any suitable diameters,such as from 0.1 millimeters to 5 millimeters. The membranes may beconfigured to be microporous and/or highly permeable to carbon oxide gasand/or hydrogen gas.

Membranes 454 may be composed of material(s) that are chemically inertto the components of at least substantially dried stream(s) 444 (and/oroutput stream 292), whether those components are in gas phase and/orliquid phase. Additionally, when membranes 454 are microporous, themembranes may be composed of one or more materials that are not wet bythe liquid phase of the components of streams 444 and/or 292, and/orliquid absorbent stream 470. In other words, the liquid phase of thosecomponents is not drawn into the micropore structure by capillaryforces. Otherwise, if the micropore structure of the membranes is filledwith the liquid phase, then relatively slow diffusion of carbon oxidegas out of the liquid-filled pores may adversely affect overallperformance of the membranes. An example of a suitable microporouspolypropylene membrane is made by Celgard®, LLC (Charlotte, N.C.).

Membrane contactor(s) 452 may direct flow of at least substantiallydried stream 444 (or intermediate stream 292, if that stream is not sentto water removal assembly 432) through a bore or lumen 458 of membranes454, as shown in FIG. 21. At least a portion of carbon oxide gas and/orhydrogen gas may pass through one or more walls 460 into the membranecontactor shell, as indicated at 462 in FIG. 21. When streams 444 or 292are directed to flow into and/or through lumen 458 of membranes 454, theinterior of the lumens may be referred to as “feed side 466” and theinterior of the shell (and/or exterior of the membranes) may be referredto as “permeate side 468.”

Alternatively, the membrane contactor(s) may direct flow of at leastsubstantially dried stream 444 (or intermediate stream 292) through themembrane contactor shell and/or over the membranes, as shown in FIG. 22.At least a portion of carbon oxide gas and/or hydrogen gas may passthrough wall(s) 460 into lumen 458 of membranes 454, as indicated at 464in FIG. 22. When streams 444 or 292 are directed to flow into and/orthrough the membrane contactor shell and/or over the membranes, theinterior of the membrane contactor shell or exterior of the membranesmay be referred to as “feed side 466” and the interior of the lumens maybe referred to as “permeate side 468.” Preferably, streams 444 or 292are directed to flow through the lumens of the membranes when the lumendiameter is small and the length of the membrane is long to prevent highpressure drops that would be encountered if liquid absorbent stream 470is directed to flow through the lumens.

Additionally, membrane contactor(s) 452 may receive at least one liquidabsorbent stream 470 at the permeate side of the membranes. The liquidabsorbent stream may be adapted to absorb at least a portion of carbonoxide gas and/or hydrogen gas that passes from the feed side to thepermeate side of membranes 454 to form liquid absorbent stream(s) 472having absorbed carbon oxide gas and/or hydrogen gas (which also may bereferred to as “spent liquid absorbent stream(s) 472”). For example,when membrane contactor(s) 452 are configured to receive at leastsubstantially dried stream 444 (or intermediate stream 292) throughlumens 458 of membranes 454, the membrane contactors may receive liquidabsorbent stream 470 in membrane contactor shell 456. Alternatively,when membrane contactor(s) 452 are configured to receive streams 444 or292 through membrane contactor shell 456, the membrane contactors mayreceive the liquid absorbent stream through lumens 458 of membranes 454.The liquid absorbent(s) in liquid absorbent stream(s) 470 may beconfigured to absorb (or bind) at least a portion of carbon oxide gasand/or hydrogen gas at relatively low temperatures and then release (ordesorb) those gas(es) at elevated temperatures. Preferably, the liquidabsorbent(s) in liquid absorbent stream(s) 470 are not driven by apressure cycle.

Membrane contactor assembly 434 may include any suitable number ofmembrane contactors 452, as shown in dashed lines in FIG. 19. Whenmembrane contactor assembly 434 includes two or more membrane contactors452, those membrane contactors may be arranged in parallel or in series.

Stripper 436 may include any suitable structure configured to receiveone or more spent liquid absorbent streams 472, strip the absorbedcarbon oxide gas and/or hydrogen gas from those stream(s), and/ordeliver one or more stripped liquid absorbent streams 474 to membranecontactor(s) 452. For example, stripper 436 may include at least onespray nozzle 476 configured to at least partially atomize the spentliquid absorbent stream into one or more sprayed spent liquid absorbentstreams 478. Stripper 436 may strip the absorbed carbon oxide gas and/orhydrogen gas via any suitable mechanism(s). For example, when the liquidabsorbent(s) used for liquid absorbent stream 470 absorbs or bindscarbon oxide gas and/or hydrogen gas within a first temperature rangeand releases or desorbs carbon oxide gas and/or hydrogen gas within asecond temperature range higher than the first temperature range, thenstripper 436 may be configured to receive one or more heated exhauststreams 480 from heating assembly 438 and direct the flow of thosestreams through the sprayed spent liquid absorbent stream(s).

The sprayed spent liquid stream(s) may be heated by the heated exhauststream(s) between 60° C. and 200° C., and preferably between 80° C. and150° C., to drive off the absorbed carbon oxide gas and/or hydrogen gasto produce or yield at least substantially regenerated liquid absorbentstream 474. The released or desorbed gasses may form at least one offgasstream 482. Stripper 436 may be operated within the range of 0 psig and50 psig, and most preferably in the range of 0 psig and 10 psig.

Heating assembly 438 may include any suitable structure configured toproduce at least one heated exhaust stream 480 for heating sprayed spentliquid absorbent stream(s) 478. For example, the heating assembly mayheat the stripper to any suitable temperature(s), such as at least aminimum release or desorption temperature for the carbon oxide gasand/or hydrogen gas in the sprayed spent liquid absorbent stream(s).

The heating assembly may include a burner assembly 484, at least one airblower 486, and an igniter assembly 488, as shown in FIG. 19. The burnerassembly may include any suitable structure configured to receive atleast one air stream 490 and at least one fuel stream 492 and to combustthe at least one fuel stream to produce heated exhaust stream(s) 480.The fuel stream(s) may be provided by feedstock delivery system 232and/or one or more of the gas removal assemblies. For example, one ormore gas removal assemblies that remove carbon oxide gas and/or hydrogengas may send those gases to burner assembly 484 as a byproduct fuelstream 494. In some embodiments, at least a portion of offgas stream 482may supplement fuel streams 492 and/or 494. Fuel streams 492, 494,and/or 482 may be delivered to burner assembly 378 via pump(s) and/orother suitable device(s). Air blower 486 may include any suitablestructure configured to generate air stream(s) 492. Igniter assembly 488may include any suitable structure configured to ignite fuel stream(s)492, 494, and/or 482.

Additionally, other configuration and types of heating assemblies 438may be used. For example, heating assembly 438 may include at least oneheater 498 that is powered by at least one power assembly 500, as shownin FIG. 23. Heater 498 may include at least one heating element 502(such as a resistive heating element). The heating element may heatspent liquid absorbent stream 472 prior to stripper 436 (and/or spraynozzle 476) and/or may heat the spent liquid absorbent stream in thestripper. Power assembly 500 may include one or more electric cords (toallow a user to plug the heater into an electrical outlet), solarpanels, wind turbines, fuel cells, etc.

Heat exchanger 440 may include any suitable structure configured totransfer heat from the stripped liquid absorbent stream(s) to the spentliquid absorbent stream(s). Pump 442 may include suitable structureconfigured to deliver or transport stripped liquid absorbent stream(s)474 to membrane contactor(s) 452 for additional absorption of carbonoxide gas and/or hydrogen gas from at least substantially dried stream444 (or intermediate stream 292).

In some embodiments, control system 340 may further include pressuremeasurement devices 504 and at least one control valve 506, as shown inFIG. 19. Pressure measurement devices 504 may include pressuretransducers or a differential pressure transducer that provides afeedback signal (typically 4-20 mA or voltage, such as 0-5 volts, 0-10volts, or 0.5 to 4.5 volts) that is registered and processed by controlassembly 342. Control valve 506 may include, for example, a proportionalvalve. Control assembly 342 may detect pressure in at leastsubstantially dried stream 444 and spent liquid absorbent stream 472 viapressure measurement devices 504, and control the control valve based,at least in part, on the detected pressures. For example, controlassembly 342 may be configured to ensure that the pressure of the spentliquid absorbent stream is higher than the pressure in the at leastsubstantially dried stream to prevent the at least substantially driedstream from flowing from the feed side to the permeate side and bubblethrough the liquid absorbent stream.

Control assembly 342 may interpret the pressure measurements from thepressure measurement devices and signal control valve 506 toproportionally open if the pressure of the spent liquid absorbent streamis above the pressure of the at least substantially dried stream by morethan a predetermined pressure (or pressure range), and to proportionallyclose if the pressure of the spent liquid absorbent stream is below thepressure of the at least substantially dried stream by less than apredetermined pressure (or pressure range). An example of apredetermined pressure range is 5 psig to 15 psig higher than thepressure of the at least substantially dried stream. However, otherpressure ranges (and/or pressures) may be selected.

In some embodiments, gas removal assembly 430 may include a shell orhousing 508 which may at least partially contain one or more othercomponents of that assembly. For example, shell 508 may at leastpartially contain membrane contactor assembly 434, stripper 436, heatingassembly 438, heat exchanger 440, and/or pump 442, as shown in FIGS. 19and 23. In some embodiments, shell 508 may include insulation and/or ajacket.

Referring back to FIG. 12, refining assembly 230 may, in someembodiments, exclude one or more components, such as excluding secondheat exchanger 289, second gas assembly 258, additional heat exchangers334, additional water removal assemblies 336, and/or additional gasremoval assemblies 338. In those embodiments, first gas removal assembly254 may generate and/or produce methane-rich stream 332.

Another example of refining assembly 30 is shown in FIG. 24, which isgenerally indicated at 510. Unless specifically excluded, refiningassembly 510 may include one or more components of the other refiningassemblies and/or other assemblies in this disclosure. Refining assembly510 may include a feedstock delivery system 512 and a fuel processingsystem 514.

Feedstock delivery system 512 may include any suitable structureconfigured to deliver one or more feed and/or fuel streams to one ormore other components of refining assembly 510. For example, thefeedstock delivery system may include a water source 516, a rich naturalgas source 518, and a pump 520. The water source may be a storage tank,a storage container, a water reservoir, a natural body of water, etc.configured to provide a water stream 522 (such as a deionized waterstream) to fuel processing system 514. Rich natural gas source 518 maybe a wellhead, a storage tank, a storage container, a desulfurizationassembly, etc. configured to provide a rich natural gas stream 524 tofuel processing system 514. Pump 520 may have any suitable structureconfigured to deliver or transport the water to fuel processing system514. The rich natural gas stream may combine with the water stream toform at least one liquid-containing feed stream 526. Alternatively, oradditionally, the rich natural gas stream may be delivered ortransported to fuel processing system 514 and combine with the waterstream at the fuel processing system. In some embodiments, feedstockdelivery system 512 may include one or more additional pumps and/orcompressors to deliver or transport rich natural gas stream 524 and/orwater stream 522 to fuel processing system 514.

Fuel processing system 514 may include any suitable structure configuredto process rich natural gas stream(s) 524, such as to increaseconcentration of methane gas and/or reduce concentration of othercomponents in the rich natural gas stream. For example, fuel processingsystem 514 may include at least one methane-producing assembly 528, aheat exchange assembly 530, a water removal assembly 532, and a membraneassembly 534.

Methane-producing assembly 528 may include any suitable structureconfigured to receive liquid-containing feed stream(s) 526 and producean output stream 536 containing methane gas as the primary component butalso containing water and other gases. For example, methane-producingassembly 528 may include at least one heavy hydrocarbon reforming (HHR)reactor 538 having a HHR catalyst 540.

Heat exchange assembly 530 may include one or more heat exchangersconfigured to transfer heat from one portion of the refining assembly toanother portion. For example, heat exchange assembly 530 may include atleast one heat exchanger 538 and one or more fans 540 configured to cooloutput stream 536. Although heat exchanger 538 is shown to cool outputstream 536 via fan(s) 540, the heat exchanger may alternatively, oradditionally, be cooled via one or more cooling fluid streams (such asone or more water streams).

Water removal assembly 532 may include any suitable structure configuredto remove water from output stream 536 to produce an at leastsubstantially dried stream 542. For example, water removal assembly 532may include at least one gas dryer 544 configured to remove at least asubstantial portion of water vapor from output stream 536 and to form atleast one reclaimed water stream 546 from the removed water vapor. Insome embodiments, the water removal assembly may include at least onewater knockout device 547 configured to remove at least a substantialportion of liquid water from output stream 536. When refining assembly510 includes one or more water knockout device(s), those devices may beimmediately upstream of (or immediately prior to) the gas dryer(s) andthe water extracted by those device(s) may form at least a portion ofreclaimed water stream 546. In some embodiments, water removal assembly532 may include a reclaimed water pump 548 configured to move ortransport the reclaimed water stream to feedstock delivery system 512,such as to add or supplement water to water source 516. The reclaimedwater stream(s) also may be sent to one or more other components ofrefining assembly 510 (such as to heat exchanger(s) 538, sent to drain,and/or otherwise disposed.

Membrane assembly 534 may include any suitable structure configured toseparate at least a portion of carbon oxide gas and/or hydrogen gas fromat least substantially dried stream 542 to form a methane-rich stream550. The separated carbon oxide gas and/or hydrogen gas may form abyproduct stream 552, which may be sent to feedstock delivery system512, one or more heating assemblies of methane-producing assembly 528,and/or other components of refining assembly 512. For example, membraneassembly 534 may include one or more carbon oxide selective membranes554 that are configured to separate carbon oxide gas and/or hydrogen gasfrom stream(s) 542. Membrane assembly 534 may include any suitablenumber of membranes 554, as shown in dashed lines in FIG. 24. Whenmembrane assembly 534 includes two or more membranes 554, thosemembranes may be arranged in parallel or in series. In some embodiments,membrane assembly 534 may include a shell or housing 555, which mayinclude any suitable structure configured to at least partially containmembranes 554. In some embodiments, shell 555 may include insulationand/or a jacket.

Refining assembly 510 may, in some embodiments, include a control system556, which may include any suitable structure configured to controloperation of the refining assembly. For example, control system 556 mayinclude a control assembly 558, one or more flow measurement devices560, one or more temperature measurement devices 562, and one or morecontrol valves 564, as shown in FIG. 24. Control assembly 558 may detectflow rate of rich natural gas stream 524 and adjust delivery (such asthe flow rate) of water stream 522 based, at least in part, on thedetected flow rate. Additionally, control assembly 558 may detecttemperatures in the HHR reactor via temperature measurement devices 562(such as thermocouples and/or other suitable devices) and adjust flowrate of the fuel stream(s) and/or byproduct fuel stream(s) to theheating assembly of that reactor via control valves 564 and/or adjustflow rate of the air stream(s) by controlling speed of the air blower(s)of that heating assembly, based, at least in part, on the detectedtemperature(s).

An example of a plate burner 566 is shown in FIG. 25, which may be usedin one or more heating assemblies described in this disclosure. Forexample, plate burner 566 may be positioned adjacent to (or to the sideof) a vaporizer. Plate burner 566 may include any suitable structureconfigured to receive at least one fuel stream 568 and to distributethat stream for combustion. For example, plate burner 566 may include anon-porous (or solid) frame 570 and first and second opposed plates 572,574. Frame 570 may include at least one inlet or input port 576configured to receive the at least one fuel stream. The frame and thefirst and second plates may define an interior 577. The inlet(s) may befluidly connected to the interior. One or both of the first and secondplates may be porous and/or may include a plurality of outlets 578,arranged orderly or randomly, for the at least one fuel stream. In use,one or more air blowers may be positioned adjacent to the first and/orsecond plates such that one or more air streams flow toward the fuelsstreams discharged from outlets 578 (such as flowing toward and aboutperpendicular to those fuel streams).

Another example of refining assembly 30 is shown in FIG. 26, which isgenerally indicated at 600. Unless specifically excluded, refiningassembly 600 may include one or more components of the other refiningassemblies and/or other assemblies in this disclosure. Refining assembly600 may include a feedstock delivery system 602 and a fuel processingsystem 604.

Feedstock delivery system 602 may include any suitable structureconfigured to deliver one or more feed and/or fuel streams to one ormore other components of refining assembly 600. For example, thefeedstock delivery system may include a water source 606, a rich naturalgas source 608, and a pump 610. The water source may be a storage tank,a storage container, a water reservoir, a natural body of water, etc.configured to provide a water stream 612 (such as a deionized waterstream) to fuel processing system 604. Rich natural gas source 608 maybe a wellhead, a storage tank, a storage container, a desulfurizationassembly, etc. configured to provide a rich natural gas stream 614 tofuel processing system 604. Pump 610 may have any suitable structureconfigured to deliver or transport the water to fuel processing system604. The rich natural gas stream may combine with the water stream toform at least one liquid-containing feed stream 616. Alternatively, oradditionally, the rich natural gas stream may be delivered ortransported to fuel processing system 604 and combine with the waterstream at the fuel processing system. In some embodiments, feedstockdelivery system 602 may include one or more additional pumps and/orcompressors to deliver or transport rich natural gas stream 614 and/orwater stream 612 to fuel processing system 604.

In some embodiments, feedstock delivery system 602 may be configured todeliver a rich natural gas slip stream 650 to methane-rich stream 640 toproduce a product methane stream 652 therefrom. Rich natural gas source608 may be fluidly connected to the output of gas removal reactor 624via one or more conduits 654.

Fuel processing system 604 may include any suitable structure configuredto process rich natural gas stream(s) 614, such as to increaseconcentration of methane gas and/or reduce concentration of othercomponents in the rich natural gas stream. For example, fuel processingsystem 604 may include at least one methane-producing assembly 618, aheat exchange assembly 620, a water removal assembly 622, and a gasremoval assembly 624.

Methane-producing assembly 618 may include any suitable structureconfigured to receive liquid-containing feed stream(s) 616 and producean output stream 626 containing methane gas as the primary component butalso containing water and other gases. For example, methane-producingassembly 618 may include at least one heavy hydrocarbon reforming (HHR)reactor 628 with a HHR catalyst 630, and a heating assembly 631configured to provide one or more heated exhaust streams to the HRRreactor.

Heat exchange assembly 620 may include one or more heat exchangersconfigured to transfer heat from one portion of the refining assembly toanother portion. For example, heat exchange assembly 620 may include atleast one heat exchanger 633 configured to cool output stream 626.

Water removal assembly 622 may include any suitable structure configuredto remove water from output stream 626 to produce an at leastsubstantially dried stream 632. For example, water removal assembly 622may include at least one gas dryer 634 configured to remove at least asubstantial portion of water vapor from output stream 626 and to form atleast one reclaimed water stream 636 from the removed water vapor. Insome embodiments, the water removal assembly may include at least onewater knockout device 637 configured to remove at least a substantialportion of liquid water from output stream 626. When refining assembly600 includes one or more water knockout device(s), those devices may beimmediately upstream of (or immediately prior to) the gas dryer(s) andthe water extracted by those device(s) may form at least a portion ofreclaimed water stream 636. In some embodiments, water removal assembly622 may include a reclaimed water pump 638 configured to move ortransport the reclaimed water stream to feedstock delivery system 602,such as to add or supplement water to water source 606. The reclaimedwater stream(s) also may be sent to one or more other components ofrefining assembly 600 (such as to heat exchanger(s) 628, sent to drain,and/or otherwise disposed.

Gas removal assembly 624 may include any suitable structure configuredto remove one or more other gases (such as carbon oxide gas and/orhydrogen gas) from at least substantially dried stream 632 to form amethane-rich stream 640 having a lower concentration of the other gasesand/or a higher concentration of methane gas. In some embodiments, themethane-rich stream may include less than 5% hydrogen gas, andpreferably less than 3% hydrogen gas; and less than 15% carbon dioxide.For example, gas removal assembly 624 may include at least one gasremoval region or reactor 642 and at least one heating assembly 644.

Gas removal reactor 642 may include any suitable structure configured toreceive one or more at least substantially dried streams 632, and toproduce one or more methane-rich streams 640. The gas removal reactormay produce the methane-rich stream via any suitable mechanism(s). Forexample, gas removal reactor 642 may generate methane-rich stream(s) 640via a methanation reaction. In that example, gas removal reactor 642 mayinclude a catalyst 646 configured to facilitate and/or promote themethanation reaction. When gas removal reactor 642 generatesmethane-rich stream(s) 640 via a methanation reaction, the gas removalreactor may be referred to as a “synthetic natural gas reactor” or “SNGreactor.”

Heating assembly 644 may include any suitable structure configured toproduce at least one heated exhaust stream for heating one or more othercomponents of the gas removal assembly. For example, the heatingassembly may heat the gas removal reactor to any suitabletemperature(s), such as at least a minimum methanation or thetemperature in which at least a portion of the carbon oxide gas andhydrogen gas in the at least substantially dried stream is reacted toproduce methane gas and water to form the methane-rich stream. Althoughgas removal assembly 624 is shown to include gas removal reactor 642,the gas removal assembly may alternatively, or additionally, include oneor more other types of gas removal assemblies, such as one or more ofthe gas removal assemblies described in the present disclosure.

Refining assembly 600 may, in some embodiments, include a control system656, which may include any suitable structure configured to controloperation of the refining assembly. For example, control system 656 mayinclude a control assembly 658, one or more sensors or measurementdevices 660, and one or more control valves 662, as shown in FIG. 26.Sensors 660 may measure one or more characteristics directly and/or maymeasure those characteristics by inference from one or more othercharacteristics.

In some embodiments, control assembly 658 may detect flow rate of richnatural gas stream 614 via flow sensor(s) 664 and adjust delivery (suchas the flow rate) of water stream 612 by controlling pump 610 based, atleast in part, on the detected flow rate. Additionally, control assembly658 may detect temperatures in the HHR reactor via temperature sensor(s)666 (such as thermocouples and/or other suitable devices) and adjustflow rate of the fuel stream(s) and/or byproduct fuel stream(s) to theheating assembly of that reactor via control valve(s) 668 and/or adjustflow rate of the air stream(s) by controlling speed of the air blower(s)of that heating assembly, based, at least in part, on the detectedtemperature(s).

In some embodiments, control assembly 658 may detect one or morecharacteristics of methane-rich stream 640 via sensor(s) 670 and adjusttemperature in the HHR reactor by adjusting flow rate of the fuelstream(s) and/or byproduct fuel stream(s) to the heating assembly ofthat reactor via control valve(s) 668 and/or adjusting flow rate of theair stream(s) by controlling speed of the air blower(s) of that heatingassembly, based, at least in part, on the detected one or morecharacteristics of the methane-rich stream. Examples of characteristicsmay include density, mass flow rate, heating value, and/or methanenumber. In some embodiments, control assembly 658 may adjust temperaturein the HHR reactor such that the methane-rich stream has at least aminimum heating value and/or minimum methane number.

In some embodiments, control assembly 658 may detect one or morecharacteristics of methane-rich stream 640 via sensor(s) 670 and adjustflow of the rich natural gas slip stream via control valve(s) 672.Sensor(s) 670 may measure, for example, the composition of themethane-rich stream, such as methane content and/or carbon dioxidecontent. The heating value and/or methane number of the rich natural gasfrom the rich natural gas source may be determined prior to operation ofthe refining assembly and/or may be determined during operation of therefining assembly via one or more sensors 674. The control assembly 658may adjust flow or flow rate of the rich natural gas slip stream suchthat the product methane stream formed by the blending of the richnatural gas slip stream and the methane-rich stream has at least aminimum heating value and/or a minimum methane number, which may beinferred from the known or measured heating value and/or methane numberof the rich natural gas from the rich natural gas source and themeasured composition of the methane-rich stream.

In some embodiments, control assembly 658 may detect one or morecharacteristics of product methane stream 652 via sensor(s) 676 andadjust flow of the rich natural gas slip stream via control valve(s)672. Sensor(s) 676 may measure, for example, composition of the productmethane stream, such as carbon dioxide and light hydrocarbon content.Control assembly 658 may calculate heating value and/or methane numberbased on the measured composition of the product methane stream andadjust flow via control valve(s) 672. Alternatively, or additionally,sensor(s) 676 may measure heating value of the product methane stream.The control assembly may adjust flow of the rich natural gas slip streamsuch that the product methane stream has at least a minimum heatingvalue and/or a minimum methane number. In some embodiments, controlassembly 658 may measure flow of the rich natural gas slip stream viasensor(s) 678 to assist the control assembly in determining theappropriate amount of flow through control valve(s) 672.

Sensor 676 may be configured to detect, resolve, and/or quantifycomposition of the product methane stream (such as light hydrocarbon andcarbon dioxide content) based on any suitable technology(ies) and/ortechnique(s). For example, sensor 676 may measure composition based oninfrared absorption spectroscopy, such as tunable filter spectroscopy.An example of such as sensor includes the Precisive® 5 Analyzer sold byMKS Instruments based in Andover, Mass. Alternatively, sensor 676 maymeasure composition based on gas chromatography. An example of a sensor676 that measures heating value is the CalorVal BTU Analyzer sold byControl Instruments Corporation based in Fairfield, N.J.

Another example of sensor 676 (and/or sensor 674) is a Coriolisflowmeter, such as the flowmeter described in U.S. Pat. No. 6,758,101.The complete disclosure of the above patent is hereby incorporated byreference for all purposes. However, sensor 676 (and/or sensor 674) mayuse other methods, such as methods of determining gas density and/ormass flow rate. Control assembly 658 may interpret the density and/ormass flow measurement measured by sensor(s) 674 and/or 676 as a heatingvalue and/or methane value of the rich natural gas slip stream and/orproduct methane stream, and may adjust the flow of the rich natural gasslip stream accordingly to meet a minimum heating value and/or minimummethane number for the product methane stream.

An example of a method of refining rich natural gas containing a firstmethane gas and other hydrocarbons that are heavier than methane gas isshown in FIG. 27 and is generally indicated at 700. Although particularsteps are shown in FIG. 27, other examples of method 700 may omit,modify, duplicate, and/or add one or more steps. Additionally, the stepsmay be performed in any suitable sequence, including sequences differentfrom FIG. 27.

At step 702, at least a substantial portion of other hydrocarbons of therich natural gas may be converted with water to an output streamcontaining a second methane gas, a lesser portion of the water, hydrogengas, and/or carbon oxide gas (such as carbon dioxide gas and/or carbonmonoxide gas). In some embodiments, converting at least a substantialportion of the other hydrocarbons may include not converting at least asubstantial portion of the first methane gas from the rich natural gas.In other words, at least a substantial portion of the first methane gasmay be allowed to pass through without conversion and/or reaction. Insome embodiments, converting at least a substantial portion of the otherhydrocarbons may include heating the rich natural gas and the water to aminimum methane-producing temperature in at least one heating assemblyand/or feeding at least a portion of at least one byproduct stream tothe heating assembly.

In some embodiments, converting at least a substantial portion of theother hydrocarbons may include measuring one or more characteristicsand/or properties of one or more streams, such as the product methanestream. For example, a heating value and/or methane number of theproduct methane stream may be detected and/or measured. In someembodiments, converting at least a substantial portion of the otherhydrocarbons may include adjusting one or more characteristics and/orproperties (of the heated rich natural gas and water based, at least inpart, on one or more of the above measured characteristics such that oneor more streams have one or more characteristics having more than and/orequal to a predetermined minimum value, less than and/or equal to apredetermined maximum value, or within a predetermined range. Forexample, adjusting temperature of the heated rich natural gas and watermay be based, at least in part, on one or more measured characteristicsof the product methane stream (e.g., heating value, methane number,etc.) such that the product methane stream has at least one of a minimumheating value or a minimum methane number.

At step 704, at least a portion of the water from the output stream maybe removed to produce an at least substantially dried stream. The watermay be in the form of water vapor and/or liquid water.

At step 706, at least a portion of carbon oxide gas and at least aportion of hydrogen gas from the at least substantially dried stream maybe converted to methane gas to form a methane-rich stream (or anintermediate stream) therefrom. The methane-rich stream may contain agreater methane concentration than the at least substantially driedstream. The methane-rich stream may form all or at least a portion ofthe product methane stream. When method 700 includes additional stepssubsequent to step 706, step 706 may form an intermediate streamcontaining a lower concentration of hydrogen gas and carbon oxide gascompared to the at least substantially dried stream. Step 706 may beperformed once or may be repeated any suitable number of times, such astwo, three, four, or more. In some embodiments, step 706 may be omitted.

In some embodiments, method 700 may include a step 708. At step 708, atleast a portion of carbon oxide gas (and/or at least a portion ofhydrogen gas) may be separated to form a byproduct stream therefrom. Theremaining portion of the intermediate stream may form at least part of amethane-rich stream having a greater methane concentration than theintermediate stream. The methane-rich stream may form all or at least aportion of the product methane stream. In some embodiments, at least aportion of the byproduct stream may be used as fuel for one or moreheating steps of method 700. In some embodiments, separating at least aportion of the carbon oxide gas may include allowing at least a portionof the carbon oxide gas to pass from a feed side to a permeate side ofat least one carbon oxide selective membrane. In some embodiments,separating at least a portion of the carbon oxide gas may includeflowing at least one liquid absorbent stream through the permeate sideof the at least one carbon oxide selective membrane to produce therefroma liquid absorbent stream having absorbed carbon oxide gas (or spentliquid absorbent stream). In some embodiments, separating at least aportion of the carbon oxide gas may include detecting pressure of theintermediate stream, detecting pressure of the spent liquid absorbentstream, and/or controlling flow of the spent liquid absorbent streamsuch that the pressure of that liquid absorbent stream is greater thanthe pressure of the intermediate stream in the feed side of the at leastone carbon oxide selective membrane. In some embodiments, separating atleast a portion of the carbon oxide gas may include heating the spentliquid absorbent stream to strip at least a substantial portion of theabsorbed carbon oxide gas to form a stripped liquid absorbent stream andan offgas stream containing the stripped carbon oxide gas.

In some embodiments, method 700 may include a step 710. At step 710, oneor more rich natural gas slip streams may be blended with themethane-rich stream to form a product methane stream therefrom. In someembodiments, blending a slip stream of rich natural gas may includemeasuring one or more characteristics and/or properties of one or morestreams, such as the product methane stream. For example, a heatingvalue and/or methane number of the product methane stream may bedetected and/or measured. In some embodiments, blending a slip stream ofrich natural gas may include adjusting one or more characteristicsand/or properties of one or more streams based, at least in part, on oneor more of the above measured characteristics and/or properties of oneor more stream such that one or more streams have one or morecharacteristics having more than and/or equal to a predetermined minimumvalue, less than and/or equal to a predetermined maximum value, orwithin a predetermined range. For example, adjusting flowrate of theslip stream may be based, at least in part, on one or more measuredcharacteristics (e.g., heating value, methane number, etc.) of theproduct methane stream such that the product methane stream has at leastone of a minimum heating value or a minimum methane number.

Refining assemblies of the present disclosure may include one or more ofthe following:

-   -   A feedstock delivery system configured to deliver at least one        liquid-containing feed stream to a methane-producing assembly.    -   A feedstock delivery system configured to deliver a rich natural        gas slip stream to a methane-rich stream to produce a product        methane stream therefrom.    -   A feedstock delivery system configured to adjust flowrate of a        rich natural gas slip stream to a methane-rich stream.    -   A feedstock delivery system configured to adjust flowrate of a        rich natural gas slip stream to a methane-rich stream based, at        least in part, on at least one measured characteristics of a        product methane stream.    -   A feedstock delivery system configured to adjust flowrate of a        rich natural gas slip stream to a methane-rich stream based, at        least in part, on at least one measured characteristics of a        product methane stream such that the product methane stream has        at least one of a minimum heating value or a minimum methane        number.    -   A methane-producing assembly configured to receive at least one        liquid-containing feed stream that includes water and rich        natural gas.    -   A methane-producing assembly configured to receive rich natural        gas and at least one liquid-containing feed stream that includes        water.    -   A methane-producing assembly configured to produce an output        stream by (a) converting at least a substantial portion of other        hydrocarbons of a rich natural gas with water to a second        methane gas, a lesser portion of the water, and other gases;        and/or (b) allowing at least a substantial portion of a first        methane gas from the rich natural gas to pass through the        methane-producing assembly unconverted.    -   A vaporizer configured to receive and/or vaporize at least a        portion of at least one liquid-containing feedstream that        includes water with or without rich natural gas to form an at        least substantially vaporized stream.    -   A methane-producing reactor containing a catalyst.    -   A methane-producing reactor configured to receive an at least        substantially vaporized stream and/or a rich natural gas stream.    -   A methane-producing reactor configured to produce an output        stream by (a) converting at least a substantial portion of other        hydrocarbons with water to a second methane gas, a lesser        portion of the water, and other gases; and (b) allowing at least        a substantial portion of a first methane gas from rich natural        gas to pass through the methane-producing reactor unconverted.    -   A heating assembly configured to produce a heated exhaust stream        for heating at least one of a vaporizer to at least a minimum        vaporization temperature and/or a methane-producing reactor to        at least a minimum methane-producing temperature.    -   A heating assembly configured to adjust temperature of a heated        exhaust stream.    -   A heating assembly configured to adjust temperature of a heated        exhaust stream based, at least in part, on at least one measured        characteristic of a product methane stream.    -   A heating assembly configured to adjust temperature of a heated        exhaust stream based, at least in part, on at least one measured        characteristic of a product methane stream such that the product        methane stream has at least one of a minimum heating value or a        minimum methane number.    -   A heating assembly including a frame and first and second        opposed plates attached to the frame and defining an interior        therebetween.    -   A frame that includes one or more inlets that are fluidly        connected to an interior and that are for receiving at least one        fuel stream.    -   One or both of first and second plates include openings defining        a plurality of outlets for at least one fuel stream.    -   A purification assembly configured to receive an output stream.    -   A purification assembly configured to produce a methane-rich        stream having a greater methane concentration than the output        stream.    -   At least one gas dryer configured to remove at least a        substantial portion of water vapor from an output stream to        produce an at least substantially dried stream.    -   At least one water knockout device configured to remove at least        a substantial portion of liquid water from an output stream.    -   A purification assembly configured to convert at least a portion        of carbon oxide gas and at least a portion of hydrogen gas in an        at least substantially dried stream to methane gas, and to        produce an intermediate stream therefrom.    -   At least one synthetic natural gas (SNG) reactor containing a        catalyst.    -   At least one SNG reactor configured to convert at least a        portion of carbon oxide gas and at least a portion of hydrogen        gas in an at least substantially dried stream to methane gas,        and to produce an intermediate stream therefrom.    -   At least one SNG reactor configured to convert at least a        portion of carbon oxide gas and at least a portion of hydrogen        gas in an at least substantially dried stream to methane gas,        and to produce a methane-rich stream therefrom.    -   A heating assembly configured to produce a heated exhaust stream        for heating at least one SNG reactor to a minimum conversion        temperature.    -   A purification assembly configured to separate at least a        portion of carbon oxide gas from an intermediate stream, and to        produce a byproduct stream therefrom.    -   At least one absorber configured to receive at least one        absorbent that is adapted to absorb at least a portion of carbon        oxide gas from an intermediate stream, and to produce a        byproduct stream therefrom.    -   At least one absorber configured to receive a liquid absorbent        stream that is adapted to absorb at least a portion of carbon        oxide gas, and/or direct flow of an intermediate stream through        the liquid absorbent stream.    -   At least one absorber configured to receive at least one solid        absorbent that is adapted to absorb carbon oxide gas, and/or to        direct flow of an intermediate stream through the at least one        solid absorbent.    -   At least one stripper configured to (a) receive a liquid        absorbent stream with absorbed carbon oxide gas, (b) strip the        carbon oxide gas from that liquid absorbent stream to form an        offgas stream therefrom, and/or (c) deliver the stripped liquid        absorbent stream to at least one absorber.    -   At least one carbon oxide selective membrane having a feed side        and a permeate side.    -   A feed side configured to receive an intermediate stream.    -   At least a portion of carbon oxide gas in an intermediate stream        is configured to pass from a feed side to a permeate side.    -   A remaining portion of an intermediate stream that remains on a        feed side forms at least part of a methane-rich stream.    -   A permeate side configured to receive a liquid absorbent stream        that is adapted to absorb at least a portion of carbon oxide gas        that passes from a feed side to a permeate side.    -   At least one stripper configured to (a) receive a liquid        absorbent stream with absorbed carbon oxide gas, (b) strip the        carbon oxide gas from that liquid absorbent stream to form a        byproduct stream therefrom, and/or (c) deliver the stripped        liquid absorbent stream to a permeate side of at least one        carbon oxide selective membrane.

Methods of refining rich natural gas may include one or more of thefollowing:

-   -   Receiving at least one liquid-containing feed stream that        includes water and rich natural gas.    -   Receiving rich natural gas and at least one liquid-containing        feed stream that includes water.    -   Vaporizing at least one liquid-containing feed stream that        includes water with or without rich natural gas to form an at        least substantially vaporized stream.    -   Receiving an at least substantially vaporized stream and/or a        rich natural gas stream.    -   Converting at least a substantial portion of other hydrocarbons        of rich natural gas with water to an output stream containing a        second methane gas, a lesser portion of the water, hydrogen gas,        and carbon oxide gas.    -   Not converting at least a substantial portion of first methane        gas from rich natural gas.    -   Heating rich natural gas and water to a minimum        methane-producing temperature via a heating assembly.    -   Measuring at least one characteristic of a product methane        stream.    -   Adjusting temperature of heated rich natural gas and water.    -   Adjusting temperature of heated rich natural gas and water        based, at least in part, on at least one measured characteristic        of a product methane stream.    -   Adjusting temperature of heated rich natural gas and water        based, at least in part, on at least one measured characteristic        of a product methane stream such that the product methane stream        has at least one of a minimum heating value or a minimum methane        number.    -   Feeding at least a portion of a byproduct stream to a heating        assembly.    -   Removing at least a portion of water from an output stream to        produce an at least substantially dried stream therefrom.    -   Converting at least a portion of carbon oxide gas and at least a        portion of hydrogen gas from an at least substantially dried        stream to methane gas to form a methane-rich stream therefrom        having a greater methane concentration than the at least        substantially dried stream.    -   Blending a slip stream of rich natural gas with a methane-rich        stream to form a product methane stream therefrom.    -   Adjusting flowrate of a slip stream of rich natural gas.    -   Adjusting flowrate of a slip stream of rich natural gas based,        at least in part, on at least one measured characteristic of a        product methane stream.    -   Adjusting flowrate of a slip stream of rich natural gas based,        at least in part, on at least one measured characteristic of a        product methane stream such that the product methane stream has        at least one of a minimum heating value or a minimum methane        number.    -   Converting at least a portion of carbon oxide gas and at least a        portion of hydrogen gas from an at least substantially dried        stream to methane gas to form an intermediate stream therefrom        containing a lower concentration of hydrogen gas and carbon        oxide gas to the at least substantially dried stream.    -   Separating, from an intermediate stream, at least a portion of        carbon oxide gas to form a byproduct stream therefrom, wherein        the remaining portion of the intermediate stream forms at least        part of a methane-rich stream having a greater methane        concentration than the intermediate stream.    -   Allowing at least a portion of carbon oxide gas to pass from a        feed side to a permeate side of at least one carbon oxide        selective membrane.    -   Flowing a liquid absorbent stream through a permeate side of at        least one carbon oxide selective membrane to produce a liquid        absorbent stream having absorbed carbon oxide gas.    -   Detecting pressure of an intermediate stream.    -   Detecting pressure of a liquid absorbent stream having absorbed        carbon oxide gas.    -   Controlling flow of a liquid absorbent stream having absorbed        carbon oxide gas such that the pressure of that liquid absorbent        stream in a permeate side of at least one carbon oxide selective        membrane is greater than a pressure of an intermediate stream in        a feed side of at least one carbon oxide selective membrane.    -   Heating a liquid absorbent stream having absorbed carbon oxide        gas to strip at least a substantial portion of absorbed carbon        oxide gas to form a stripped liquid absorbent stream and an        offgas stream containing stripped carbon oxide gas.

INDUSTRIAL APPLICABILITY

The present disclosure, including refining assemblies for rich naturalgas, and components of those assemblies, is applicable to thefuel-processing and other industries in which methane gas is purified,produced, and/or utilized, such as for fueling an engine and/orelectrical power generation.

The disclosure set forth above encompasses multiple distinct inventionswith independent utility. While each of these inventions has beendisclosed in its preferred form, the specific embodiments thereof asdisclosed and illustrated herein are not to be considered in a limitingsense as numerous variations are possible. The subject matter of theinventions includes all novel and non-obvious combinations andsubcombinations of the various elements, features, functions and/orproperties disclosed herein. Similarly, where any claim recites “a” or“a first” element or the equivalent thereof, such claim should beunderstood to include incorporation of one or more such elements,neither requiring nor excluding two or more such elements.

Inventions embodied in various combinations and subcombinations offeatures, functions, elements, and/or properties may be claimed throughpresentation of new claims in a related application. Such new claims,whether they are directed to a different invention or directed to thesame invention, whether different, broader, narrower or equal in scopeto the original claims, are also regarded as included within the subjectmatter of the inventions of the present disclosure.

What is claimed is:
 1. A refining assembly for rich natural gascontaining a first methane gas and other hydrocarbons that are heavierthan methane gas, comprising: a methane-producing assembly configured toreceive at least one liquid-containing feed stream that includes waterand rich natural gas and to produce an output stream therefrom by (a)converting at least a substantial portion of the other hydrocarbons ofthe rich natural gas with the water to a second methane gas, a lesserportion of the water, and other gases, and (b) allowing at least asubstantial portion of the first methane gas from the rich natural gasto pass through the methane-producing assembly unconverted; apurification assembly configured to receive the output stream and toproduce a methane-rich stream therefrom having a greater methaneconcentration than the output stream; a feedstock delivery systemconfigured to (1) deliver the at least one liquid-containing feed streamto the methane-producing assembly, (2) deliver a rich natural gas slipstream to the methane-rich stream to produce a product methane streamtherefrom, and (3) adjust flowrate of the rich natural gas slip streamto the methane-rich stream based, at least in part, on at least onemeasured characteristic of the product methane stream such that theproduct methane stream has at least one of a minimum heating value or aminimum methane number.
 2. A refining assembly for rich natural gascontaining a first methane gas and other hydrocarbons that are heavierthan methane gas, comprising: a methane-producing assembly configured toreceive at least one liquid-containing feed stream that includes waterand rich natural gas and to produce an output stream therefrom by (a)converting at least a substantial portion of the other hydrocarbons ofthe rich natural gas with the water to a second methane gas, a lesserportion of the water, and other gases, and (b) allowing at least asubstantial portion of the first methane gas from the rich natural gasto pass through the methane-producing assembly unconverted; and apurification assembly configured to receive the output stream and toproduce a methane-rich stream therefrom having a greater methaneconcentration than the output stream, wherein the methane-producingassembly includes: a vaporizer configured to receive and vaporize atleast a portion of the at least one liquid-containing feedstream thatincludes water and rich natural gas to form an at least substantiallyvaporized stream; a methane-producing reactor containing a catalyst andconfigured to receive the at least substantially vaporized stream and toproduce the output stream by (a) converting at least a substantialportion of the other hydrocarbons with the water to the second methanegas, a lesser portion of the water, and the other gases and (b) allowingat least a substantial portion of the first methane gas from the richnatural gas to pass through the methane-producing reactor unconverted;and a heating assembly configured to produce a heated exhaust stream forheating at least one of the vaporizer to at least a minimum vaporizationtemperature or the methane-producing reactor to at least a minimummethane-producing temperature, and wherein the heating assembly isconfigured to adjust temperature of the heated exhaust stream based, atleast in part, on at least one measured characteristic of the productmethane stream such that the product methane stream has at least one ofa minimum heating value or a minimum methane number.
 3. A refiningassembly for rich natural gas containing a first methane gas and otherhydrocarbons that are heavier than methane gas, comprising: amethane-producing assembly configured to receive at least oneliquid-containing feed stream that includes water and rich natural gasand to produce an output stream therefrom by (a) converting at least asubstantial portion of the other hydrocarbons of the rich natural gaswith the water to a second methane gas, a lesser portion of the water,and other gases, and (b) allowing at least a substantial portion of thefirst methane gas from the rich natural gas to pass through themethane-producing assembly unconverted; a purification assemblyconfigured to receive the output stream and to produce a methane-richstream therefrom having a greater methane concentration than the outputstream, where the output stream includes water vapor, wherein thepurification assembly includes at least one gas dryer configured toremove at least a substantial portion of the water vapor from the outputstream to produce an at least substantially dried stream, and whereinthe purification assembly includes: at least one synthetic natural gas(SNG) reactor containing a catalyst and configured to convert at least aportion of the carbon oxide gas and at least a portion of the hydrogengas in the at least substantially dried stream to methane gas, and toproduce the methane-rich stream therefrom, and a heating assemblyconfigured to produce a heated exhaust stream for heating the at leastone SNG reactor to a minimum conversion temperature; and a feedstockdelivery system configured to deliver (1) the at least oneliquid-containing feed stream to the methane-producing assembly and (2)a rich natural gas slip stream to the methane-rich stream to produce aproduct methane stream therefrom.
 4. The refining assembly of claim 3,wherein the feedstock delivery system is configured to adjust flowrateof the rich natural gas slip stream to the methane-rich stream based, atleast in part, on at least one measured characteristic of the productmethane stream such that the product methane stream has at least one ofa minimum heating value or a minimum methane number.
 5. A method ofrefining rich natural gas containing a first methane gas and otherhydrocarbons that are heavier than methane gas, comprising: convertingat least a substantial portion of the other hydrocarbons of the richnatural gas with water to an output stream containing a second methanegas, a lesser portion of the water, hydrogen gas, and carbon oxide gas,wherein converting at least a substantial portion of the otherhydrocarbons includes not converting at least a substantial portion ofthe first methane gas from the rich natural gas; removing at least aportion of the water from the output stream to produce an at leastsubstantially dried stream therefrom; converting at least a portion ofthe carbon oxide gas and at least a portion of the hydrogen gas from theat least substantially dried stream to methane gas to form anintermediate stream therefrom containing a lower concentration ofhydrogen gas and carbon oxide gas compared to the at least substantiallydried stream; separating, from the intermediate stream, at least aportion of the carbon oxide gas to form a byproduct stream therefrom,wherein the remaining portion of the intermediate stream forms at leastpart of a methane-rich stream having a greater methane concentrationthan the intermediate stream, wherein converting at least a substantialportion of the other hydrocarbons of the rich natural gas with waterincludes heating the rich natural gas and the water; measuring at leastone characteristic of the product methane stream; and adjustingtemperature of the heated rich natural gas and water based, at least inpart, on at least one measured characteristic of the product methanestream such that the product methane stream has at least one of aminimum heating value or a minimum methane number.
 6. A method ofrefining rich natural gas containing a first methane gas and otherhydrocarbons that are heavier than methane gas, comprising: convertingat least a substantial portion of the other hydrocarbons of the richnatural gas with water to an output stream containing a second methanegas, a lesser portion of the water, hydrogen gas, and carbon oxide gas,wherein converting at least a substantial portion of the otherhydrocarbons includes not converting at least a substantial portion ofthe first methane gas from the rich natural gas; removing at least aportion of the water from the output stream to produce an at leastsubstantially dried stream therefrom; converting at least a portion ofthe carbon oxide gas and at least a portion of the hydrogen gas from theat least substantially dried stream to methane gas to form anintermediate stream therefrom containing a lower concentration ofhydrogen gas and carbon oxide gas compared to the at least substantiallydried stream; separating, from the intermediate stream, at least aportion of the carbon oxide gas to form a byproduct stream therefrom,wherein the remaining portion of the intermediate stream forms at leastpart of a methane-rich stream having a greater methane concentrationthan the intermediate stream; and blending a slip stream of rich naturalgas with the methane-rich stream to form a product methane streamtherefrom.
 7. The method of claim 6, wherein blending a slip stream ofrich natural gas includes: measuring at least one characteristic of theproduct methane stream; and adjusting flowrate of the slip stream ofrich natural gas based, at least in part, on at least one measuredcharacteristic of the product methane stream such that the productmethane stream has at least one of a minimum heating value or a minimummethane number.
 8. A refining assembly for rich natural gas containing afirst methane gas and other hydrocarbons that are heavier than methanegas, comprising: a vaporizer configured to receive and vaporize at leasta portion of at least one liquid-containing feedstream that includeswater and rich natural gas to form an at least substantially vaporizedstream; a methane-producing reactor containing a catalyst and configuredto receive the vaporized feed stream and to produce an output stream by(a) converting at least a substantial portion of the other hydrocarbonswith the water to a second methane gas, a lesser portion of the water,hydrogen gas, and carbon oxide gas, and (b) allowing at least asubstantial portion of the first methane gas from the rich natural topass through the methane-producing reactor unconverted; a first heatingassembly configured to receive at least one fuel stream and at least oneair stream and produce a heated exhaust stream for heating at least oneof the vaporizer to at least a minimum vaporization temperature or themethane-producing reactor to at least a minimum methane-producingtemperature; a purification assembly configured to receive the outputstream and to produce a methane-rich stream therefrom having a greatermethane concentration than the output stream; a feedstock deliverysystem configured to (1) deliver the at least one liquid-containing feedstream to the vaporizer, (2) deliver a rich natural gas slip stream tothe methane-rich stream to produce a product methane stream therefrom,and (3) adjust flowrate of the rich natural gas slip stream to themethane-rich stream based, at least in part, on at least one measuredcharacteristic of the product methane stream such that the productmethane stream has at least one of a minimum heating value or a minimummethane number.
 9. A refining assembly for rich natural gas containing afirst methane gas and other hydrocarbons that are heavier than methanegas, comprising: a vaporizer configured to receive and vaporize at leasta portion of at least one liquid-containing feedstream that includeswater and rich natural gas to form an at least substantially vaporizedstream; a methane-producing reactor containing a catalyst and configuredto receive the vaporized feed stream and to produce an output stream by(a) converting at least a substantial portion of the other hydrocarbonswith the water to a second methane gas, a lesser portion of the water,hydrogen gas, and carbon oxide gas, and (b) allowing at least asubstantial portion of the first methane gas from the rich natural topass through the methane-producing reactor unconverted; a first heatingassembly configured to receive at least one fuel stream and at least oneair stream and produce a heated exhaust stream for heating at least oneof the vaporizer to at least a minimum vaporization temperature or themethane-producing reactor to at least a minimum methane-producingtemperature; and a purification assembly configured to receive theoutput stream and to produce a methane-rich stream therefrom having agreater methane concentration than the output stream, wherein thepurification assembly includes at least one of a gas dryer or a waterknockout device configured to remove at least a substantial portion ofwater from the output stream to produce an at least substantially driedstream, wherein the purification assembly includes: at least onesynthetic natural gas (SNG) reactor containing a catalyst and configuredto convert at least a portion of the carbon oxide gas and at least aportion of the hydrogen gas in the at least substantially dried streamto methane gas, and to produce the methane-rich stream therefrom, and asecond heating assembly configured to produce a heated exhaust streamfor heating the at least one SNG reactor to a minimum conversiontemperature; and a feedstock delivery system configured to deliver (1)the at least one liquid-containing feed stream to the vaporizer and (2)a rich natural gas slip stream to the methane-rich stream to produce aproduct methane stream therefrom.
 10. The refining assembly of claim 9,wherein the feedstock delivery system is configured to adjust flowrateof the rich natural gas slip stream to the methane-rich stream based, atleast in part, on at least one measured characteristic of the productmethane stream such that the product methane stream has at least one ofa minimum heating value or a minimum methane number.
 11. A method ofrefining rich natural gas containing a first methane gas and otherhydrocarbons that are heavier than methane gas, comprising: convertingat least a substantial portion of the other hydrocarbons of the richnatural gas with water to an output stream containing a second methanegas, a lesser portion of the water, hydrogen gas, and carbon oxide gas,wherein converting at least a substantial portion of the otherhydrocarbons includes not converting at least a substantial portion ofthe first methane gas from the rich natural gas; removing at least aportion of the water from the output stream to produce an at leastsubstantially dried stream therefrom; converting at least a portion ofthe carbon oxide gas and at least a portion of the hydrogen gas from theat least substantially dried stream to methane gas to form amethane-rich stream having a greater methane concentration than theintermediate stream, wherein converting at least a substantial portionof the other hydrocarbons of the rich natural gas with water includesheating the rich natural gas and the water; measuring at least onecharacteristic of the product methane stream; and adjusting temperatureof the heated rich natural gas and water based, at least in part, on atleast one measured characteristic of the product methane stream suchthat the product methane stream has at least one of a minimum heatingvalue or a minimum methane number.
 12. A method of refining rich naturalgas containing a first methane gas and other hydrocarbons that areheavier than methane gas, comprising: converting at least a substantialportion of the other hydrocarbons of the rich natural gas with water toan output stream containing a second methane gas, a lesser portion ofthe water, hydrogen gas, and carbon oxide gas, wherein converting atleast a substantial portion of the other hydrocarbons includes notconverting at least a substantial portion of the first methane gas fromthe rich natural gas; removing at least a portion of the water from theoutput stream to produce an at least substantially dried streamtherefrom; converting at least a portion of the carbon oxide gas and atleast a portion of the hydrogen gas from the at least substantiallydried stream to methane gas to form a methane-rich stream having agreater methane concentration than the intermediate stream; blending aslip stream of rich natural gas with the methane-rich stream to form aproduct methane stream therefrom.
 13. The method of claim 12, whereinblending a slip stream of rich natural gas includes: measuring at leastone characteristic of the product methane stream; and adjusting flowrateof the slip stream of rich natural gas based, at least in part, on themeasured characteristic.